ML031340032

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IR 05000247-03-003, on December 29, 2002 - March 29, 2003, Entergy Nuclear Operations, Inc.; Indian Point 2 Nuclear Power Plant; Maintenance Risk Assessment/Emergent Work, Post Maintenance Testing; and Radioactive Material Processing and Tr
ML031340032
Person / Time
Site: Indian Point Entergy icon.png
Issue date: 05/13/2003
From: Brian Holian
Division of Nuclear Materials Safety I
To: Dacimo F
Entergy Nuclear Operations
References
FOIA/PA-2003-0379, FOIA/PA-2003-0388, FOIA/PA-2004-0042 IR-03-003
Download: ML031340032 (46)
v • d • e


See also: IR 05000247/2003003

Text

May 13, 2003

Mr. Fred Dacimo

Vice President - Operations

Entergy Nuclear Operations, Inc.

Indian Point Nuclear Generating Units 1 & 2

295 Broadway, Suite 1

Post Office Box 249

Buchanan, NY 10511-0249

SUBJECT: INDIAN POINT 2 - NRC INTEGRATED INSPECTION REPORT 50-247/03-03

Dear Mr. Dacimo:

On March 29, 2003, the US Nuclear Regulatory Commission (NRC) completed an inspection at

the Indian Point 2 Nuclear Power Plant. The enclosed integrated inspection report documents

the inspection findings, which were discussed on April 9, 2003, with yourself and other members

of your staff.

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

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed

personnel.

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

significance (Green), all of which were determined to be violations of NRC requirements.

However, because of their very low safety significance and because the issues have been

addressed and entered into your corrective action program, the NRC is treating these issues as

Non-Cited Violations, in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you

deny these Non-Cited Violations, you should provide a response with the basis for your denial,

within 30 days of the receipt 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

the Indian Point 2 facility.

Since the terrorist attacks on September 11, 2001, the NRC has issued five Orders (dated

February 25, 2002, January 7, 2003, and three on April 29, 2003) and several threat advisories

to licensees of commercial power reactors to strengthen licensee security capabilities, improve

security force readiness and training, and enhance access authorization. The NRC also issued

Temporary Instruction 2515/148 on August 28, 2002, that provided guidance to inspectors to

audit and inspect licensee implementation of the interim compensatory measures (ICMs)

required by the February 25th Order. Phase 1 of TI 2515/148 was completed at all commercial

nuclear power plants during calendar year (CY) 02, and the remaining inspections are

scheduled for completion in CY 03. Additionally, table-top security drills were conducted at

several licensees to evaluate the impact of expanded adversary characteristics and the ICMs on

licensee protection and mitigative strategies. Information gained and discrepancies identified

Mr. Fred Dacimo 2

during the audits and drills were reviewed and dispositioned by the Office of Nuclear Security

and Incident Response. For CY 03, the NRC will continue to monitor overall safeguards and

security controls, conduct inspections, and resume force-on-force exercises at selected power

plants. The Indian Point site will receive a pilot force-on-force exercise this summer. Should

threat conditions change, the USNRC may issue additional Orders, advisories, and temporary

instructions to ensure adequate safety is being maintained at all commercial power reactors.

The inspectors reviewed eight effectiveness reviews associated with the Fundamental

Improvement Plan (FIP). The FIP was an improvement plan initiated in early 2002 in response

to the NRCs classification of Indian Point Unit 2 as a multiple degraded cornerstone column

facility. The effectiveness reviews evaluated the quality of corrective actions in specific areas

and concluded if those actions had improved performance. Specific areas evaluated included:

management observation of work activities; operator burden and work-down curve for temporary

alterations; review of the design basis initiative project; optimization of the preventive

maintenance program; corrective actions in monitoring the work control process; equipment

reliability actions; work management self-assessments; and corrective action effectiveness

reviews for condition reports. The inspectors concluded that the effectiveness reviews were not

uniformly self-critical or consistent with recent NRC assessments or performance metrics. For

example, the effectiveness review for the design basis initiative project primarily focused on the

quality of action plans and efficiencies of plan implementation, instead of the quality of the

engineering staffs products or recently developed design information road maps. However,

the inspectors did note that the 2003 Indian Point Business Plan does provide appropriate

actions to support improvements in the key areas addressed in the FIP. Your attention to the

quality of self-assessments remains an important element to continued station improvement.

In accordance with 10 CFR 2.790 of the NRC's "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). Should you have any questions

regarding this report, please contact Mr. Peter Eselgroth at 610-337-5234.

Sincerely,

/RA/

Brian E. Holian, Deputy Director

Division of Reactor Projects

Docket No.50-247

License No. DPR-26

Enclosure: Inspection Report 50-247/03-03

W/Attachment: Supplemental Information

cc w/encl: G. J. Taylor, Chief Executive Officer, Entergy Nuclear

M. R. Kansler, President - Entergy Nuclear Northeast

Mr. Fred Dacimo 3

J. Herron, Senior Vice President, Indian Point Energy Center

C. Schwarz, General Manager - Plant Operations

D. Pace, Vice President, Engineering

J. Knubel, Vice President, Operations Support

J. McCann, Manager, Nuclear Safety and Licensing

J. Kelly, Director, Nuclear Safety Assurance

C. Faison, Manager, Licensing

H. Salmon, Jr., Director of Oversight

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

W. Flynn, 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

B. Brandenburg, Assistant General Counsel

P. Rubin, Operations Manager

Assemblywoman Sandra Galef, NYS Assembly

C. Terry, Niagara Mohawk Power Corporation

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 Citizen's 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 Hilary Rodham Clinton

Senator Charles Schumer

J. Riccio, Greenpeace

A. Matthiessen, Executive Director, Riverkeepers, Inc.

M. Kapolwitz, Chairman of County Environment & Health Committee

A. Reynolds, Environmental Advocates

Mr. Fred Dacimo 4

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. Copeland, Pace Environmental Litigation Clinic

R. Witherspoon, The Journal News

Mr. Fred Dacimo 5

Distribution w/encl: H. Miller, RA/J. Wiggins, DRA (1)

H. Nieh, RI EDO Coordinator

P. Habighorst, SRI - Indian Point 2

R. Laufer, NRR

P. Eselgroth, DRP

P. Milano, PM, NRR

G. Vissing, PM, NRR (Backup)

W. Cook, DRP

R. Junod, DRP

R. Martin, DRP

Region I Docket Room (w/concurrences)

DOCUMENT NAME: C:\ORPCheckout\FileNET\ML031340032.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 E RI/DRP E

NAME PHabighorst/PWE for PEselgroth/PWE BHolian/BEH

DATE 05/13/03 05/13/03 05/13/03

OFFICIAL RECORD COPY

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No. 50-247

License No. DPR-26

Report No. 50-247/03-03

Licensee: Entergy Nuclear Operations, Inc.

Facility: Indian Point 2 Nuclear Power Plant

Location: Buchanan, New York 10511

Dates: December 29, 2002 - March 29, 2003

Inspectors: Peter Habighorst, Senior Resident Inspector

Lois James, Resident Inspector

Jason C. Jang, Senior Health Physicist (1/6-1/10/03)

William Cook, Senior Project Engineer (3/10-3/14/03)

David Silk, Emergency Preparedness Specialist (1/6-29/03)

Daniel Barss, Emergency Preparedness Specialist (1/6-29/03),

Thomas Burns, Senior Reactor Engineer, DRS (2/10-2/13/03)

John R. McFadden, Health Physicist, DRS (2/24-2/28/03)

Leonard Cheung, Sr. Reactor Engineer, DRS (11/4-11/9/02)

Approved by: Peter W. Eselgroth, Chief

Projects Branch 2

Division of Reactor Projects

i Enclosure

TABLE OF CONTENTS

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii

SUMMARY OF PLANT STATUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

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

1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1R06 Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1R11 Operator Requalification Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R13 Maintenance Risk Assessment and Emergent Work Activities . . . . . . . . . . . . . . 8

1R14 Personnel Performance During Non-Routine Plant Evolutions and Events . . . 11

1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

1R17 Permanent Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1R19 Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

1EP4 Emergency Action Level and Emergency Plan Changes . . . . . . . . . . . . . . . . . 17

1EP6 Emergency Plan Drills . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2. RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

2OS1 Access Control to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 18

2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2OS3 Radiation Monitoring Instrumentation and Protective Equipment . . . . . . . . . . . 20

2PS1 Gaseous and Liquid Effluents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

2PS2 Radioactive Material Processing and Transportation . . . . . . . . . . . . . . . . . . . . 22

4. OTHER ACTIVITIES (OA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

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

4OA3 Event Follow-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

4OA5 Review of Institute of Nuclear Power Operations (INPO) Evaluation Report . . 29

4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

ATTACHMENT: SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

LIST OF BASELINE INSPECTIONS PERFORMED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

ii Enclosure

SUMMARY OF FINDINGS

IR 05000247-03-03, on December 29, 2002 - March 29, 2003, Entergy Nuclear Operations, Inc.;

Indian Point 2 Nuclear Power Plant; Maintenance Risk Assessment/Emergent Work, Post

Maintenance Testing; and Radioactive Material Processing and Transportation.

The report covered a twelve-week period of inspection by resident, region-based, and

headquarters-based inspectors. Four Green non-cited violations (NCVs), and two unresolved

items were identified. The significance of the findings are indicated by their color (Green, White,

Yellow, Red) in accordance with Inspection Manual Chapter (IMC) 0609, Significance

Determination Process (SDP). The NRCs program for overseeing the safe operation of

commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 3, dated July, 2000.

A. NRC- Identified and Self-Revealing Findings

Cornerstone: Initiating Events

  • Green. On February 7, 2003, a self-revealing finding involved inadequate

emergent work instructions that resulted in an electrical short during replacement

of the 22 steam generator low level bistable. The electrical short caused a

breaker trip on circuit 10 of instrument bus 21and the resultant loss of electrical

power to the pressurizer level and reactor coolant system pressure control

channels (failed low). The inadequate work instructions is considered a non-cited

violation of 10 CFR 50 Appendix B, Criterion V, since the instructions did not

account for consideration of performing this replacement with the circuit de-

energized or the proximity to other reactor protection system relays.

The performance issue is more than minor since the operators were required to

take action to restore reactor coolant system pressure and pressurizer level to

preclude a reactor trip. The finding involves the initiating events cornerstone in

that it increased the likelihood of upset in plant stability and it involves human

error during the planning of an emergent work activity. This finding is considered

to be of very low safety significance in that in accordance with NRC Manual

Chapter 0609, Appendix A, the finding did not contribute to the likelihood of a

secondary or primary LOCA initiator and it did not contribute to either a reactor

trip or mitigation system unavailability. (Section 1R13)

Cornerstone: Mitigating Systems

  • Green. A self-revealing event was identified on February 26, 2003, when

operators observed no boric acid flow to the reactor vessel via the No. 22 boric

acid transfer pump (BATP). It was determined that during preventative

maintenance activities in March 2001, the post-work test on the No. 22 BATP

outlet valve to the boric acid filter stop was inadequate to identify that the valve

finger plate was installed upside down. This finding is considered a non-cited

violation of 10 CFR 50 Appendix B, Criterion V. This event is considered more

than minor because the improperly installed valve plate affected the availability of

one train of emergency boration. This is considered to be of very low risk

iii Enclosure

Summary of Findings (contd)

significance in accordance with NRC MC 0609 Appendix A, since the emergency

boration function was not lost due to this performance issue. (Section 1R19)

  • Green. The inspectors identified that ineffective corrective actions resulted in

repetitive surveillance test failures of the 23 emergency diesel generator between

December 2001 and February 2003. This finding is considered a non-cited

violation of 10 CFR 50, Appendix B, Criterion XVI. The finding is more than minor

because the surveillance test failures impacted the availability of one train of

emergency AC power source. This finding was of very low risk significance

because the repetitive failures did not result in an actual loss of function for the

emergency AC power. (Section 1R13)

Cornerstone: Public Safety

  • Green. A self-revealing non-cited violation of 10 CFR 71.12 was identified for

failure to comply with shipping cask package procedures. On February 6, 2003, a

CNS 8-120 B cask was received from the Indian Point Energy Center at a

consolidation facility in South Carolina with a bolt missing on the primary lids

pressure test port in violation of the cask use and maintenance procedures. This

finding was more than minor in that it was associated with the Public Radiation

Safety Cornerstones attribute of procedures for transportation packages. The

finding affected the associated cornerstone objective to ensure adequate

protection of public health and safety from exposure to radioactive materials

contained in an NRC-approved Type B package released into the public domain.

The finding was determined to be of very low safety significance in that the finding

did not involve exceeding transportation radiation limits, there was no breach of

the package during transit, and the issue was a Certificate of Compliance

maintenance/use performance deficiency. (Section 2PS2)

iv Enclosure

REPORT DETAILS

SUMMARY OF PLANT STATUS

1. REACTOR SAFETY

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

Planning

1R04 Equipment Alignment

a. Inspection Scope

.1 Partial System Walkdowns

On January 23, 2003, the inspector performed a partial system walkdown of the 22

auxiliary feedwater pump (AFWP) train while the 23 AFWP train was out of service for

preventive maintenance. The purpose of this walkdown was to verify equipment

alignment and identify any discrepancies that could adversely impact the function of the

steam driven auxiliary feedwater pump train. The inspector observed the physical

condition of the system pump and valves and reviewed the operations logs. The

inspector used check-off lists (COLs) 21.3, Steam Generator Water Level and Auxiliary

Boiler Feedwater and 18.1, Main and Reheat Steam, for this walkdown and reviewed

the design basis document for the auxiliary feedwater system and Technical Specification 3.4 to verify the valve positions, as defined in the COL, were appropriate.

On February 25, 2003, the inspector performed a system walkdown of the fuel oil portion

of the emergency diesel generator (EDG) system while the 21 EDG was out of service

for preventive maintenance. The purpose of this walkdown was to verify equipment

alignment and identify any discrepancies that could adversely impact the operation of the

remaining EDGs and thereby increase risk. The inspector observed the physical

condition of the fuel oil system pumps and valves. The inspector used COL 27.3.1,

Diesel Generators, for this walkdown and reviewed the design basis document for the

diesel generator fuel oil system.

On March 11, 2003, the inspector performed a system walkdown of the 21 containment

spray system while the 22 containment spray pump was out of service for planned testing

and preventative maintenance. The purpose of this walkdown was to verify equipment

alignment and identify any discrepancies that could adversely impact the function of the

containment spray system and thereby increase risk. The inspector observed the

physical condition of the containment spray pump and valves. The inspector used COL

10.2.1, Containment Spray System, system operating procedure (SOP) 10.2.1,

Containment Spray System Operation, and plant drawings 9321-F-2735-130 and

A225296. Minor deficiencies involving plant labeling and plant drawing errors were

provided to the licensee and addressed via the corrective action process. The

inspectors review of an operability determination for the containment pressure

instruments is documented in report section 1R15.

b. Findings

Enclosure

2

No findings of significance were identified.

.2 Full System Alignment

a. Inspection Scope

The inspector performed a walkdown of accessible portions of the engineered

safeguards features system (ESFS) to verify electrical separation between channels and

identify any discrepancies that may adversely impact the function of the system. The

inspector also verified that the licensee had properly identified and resolved equipment

problems that could impact the availability and functional capability of this accident

mitigation system. The inspector selected the ESFS based upon its importance to plant

safety and risk. This system is in the top twenty systems at the unit based upon risk

achievement worth (which measures the relative risk of systems based on IPE data).

The inspector reviewed the following documents to confirm system availability and

functional capability:

  • The Technical Specifications for the ESFS, Section 3.5.3
  • Maintenance Rule Background Document for ESFS
  • Outstanding elective and corrective maintenance activities associated with ESFS
  • Outstanding control room deficiencies associated with ESFS
  • Last completed Technical Specification surveillances: PC-R4, Pressurizer

Pressure; PC-R4-1, Pressurizer Pressure Transmitters; PT-Q55, Pressurizer

Pressure; PC-R29, Main Steam Line Flow Instrumentation - CCR; PT-Q63,

Steam Flow/Feedwater Flow Mismatch Bistables; and PC-R32-1, Main Feedwater

Flow - Transmitters;

  • System Engineering Health Reports for ESFS for 4th quarter of 2002
  • SE-350 Attachment 8.2, System Monitoring Basis Document for ESFS
  • Design Basis Document for Engineered Safeguards Feature System
  • Abnormal Operating Instruction 10.1.4, Safeguards Relays DC Power Failure

b. Findings

No findings of significance were identified.

Enclosure

3

1R05 Fire Protection

.1 Fire Zone Tours

a. Inspection Scope

The inspector toured the areas important to plant safety and risk based upon a review of

Section 4.0, Internal Fires Analysis, and Table 4.6-2, Summary of Core Damage

Frequency Contributions from Fire Zones, in the Indian Point 2 Individual Plant

Examination for External Events (IPEEE). The objective of this inspection was to

determine if the licensee 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) licensee 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:

  • Fire Zone 63A, circulating water pumps area
  • Fire Zone 610, Unit 1 screenwell room
  • Fire Zone 23, 480V switchgear room
  • Fire Zone 6A, Waste Storage and Drumming Station
  • Fire Zone 74A and 74B, Electrical Penetration Areas of the Fan House
  • Fire Zone 7A, 80-foot elevation of Primary Auxiliary Building
  • Fire Zone 43A, 15-foot elevation of Turbine Building

Reference material consulted by the inspector included the Fire Protection

Implementation Plan, Pre-Fire Plan, and Station Administrative Order (SAO)-700, Fire

Protection and Prevention Policy, SAO-701, Control of Combustibles and Transient Fire

Load, SAO-703, Fire Protection Impairment Criteria and Surveillance, and Calculation

PGI-00433, Combustible Loading Calculation. The inspector identified a number of

minor items related to drawing errors in the pre-fire plan sketch, and penetration drawing

errors and housekeeping concerns. The associated condition reports for these minor

errors are identified in the Attachment to this inspection report.

b. Findings

No findings of significance were identified.

Enclosure

4

.2 Lack of Cable Separation in Fire Areas F and J

a. Inspection Scope

On February 6, 2003, Entergy identified that the routing of charging pump power supply

and control cables do not meet the cable separation criteria specified in 10 CFR 50

Appendix R,Section III.G.1. This was reported to the NRC via 10 CFR 50.72(b)(3)(ii)(B)

(Event Notification 39571) as an unanalyzed condition and documented in condition

report IP2-2003-00765. A postulated fire in Fire Area F (fire zones 6, 7 and 7A) would

disable all three charging pumps. The postulated fire could result in the loss of: the

23 charging pump alternate power feed transfer switch; 23 charging pump alternate

power feed; the alternate/normal power feed cable between the transfer switch and the

pump; 22 charging pump power feed cable; local/remote control cabling (disabling

remote operation of all charging pump breakers); and the control cables and pneumatics

for the 22 and 23 charging pumps.

This design vulnerability was identified by Entergy during a re-baseline analysis to

validate compliance with 10 CFR 50 Appendix R. Entergys review was being performed

under a design basis initiative project (DBI-PI-1) in response to previously identified

concerns about the analysis. Efforts include the location of all Appendix R credited

equipment, power, control and instrument cables, power sources, local controls and

indication, and other features by fire area and fire zone.

On February 12, 2003, Entergy identified that the normal and emergency power supplies

to the six service water pumps were routed through manhole 23 (Unit 2 turbine building

under the 15 elevation) and are completely separated from the fire area except for

manhole 23. The alternate safety shutdown power cables run approximately 200 feet to

the south. The alternate power supply cables for two of the six service water pumps are

routed unprotected from Fire Area J through Fire Area A at the south end of the Unit 1

turbine building. The vulnerability is a postulated fire in Fire area J that could result in a

complete loss of power to all service water pumps. This was reported to the NRC as an

undated to Event Notification 39571. Condition Report IP2-2003-867 documented this

deficiency.

The inspector reviewed and verified that licensee compensatory measures for the

vulnerabilities in Fire Areas F and J were consistent with SAO-703, Fire Protection

Impairment Criteria and Surveillance, Addendum I, item 9. The inspector walked down

the areas to confirm Entergys conclusions regarding the fire vulnerability. The inspector

reviewed the following documents:

  • Abnormal Operating Instruction (AOI)27.1.9, Control Room Inaccessibility Safe

Shutdown Control

  • OASL 15.11, Attachment 1, 480 Volt DB-50 Breaker Operations
  • Individual Plant Examination for External Events (IPEEE)

b. Findings

Enclosure

5

The licensee-identified postulated fire vulnerabilities within Fire Zones F and J are

considered unresolved (URI 50-247/03-03-01). A preliminary assessment of these cable

separation discrepancies identifies them as low safety consequence, based upon:

previous inspection review of the alternate safe shutdown capability and fire protection

program implementation (reference inspection report No. 50-247/2000-004, dated

May 17, 2001); low combustible loading in the affected fire zones; appropriate

compensatory measures in place until final resolution; and low risk significance based

upon current IPEEE analysis of the affected fire zones. This issue will remain unresolved

pending the completion of the NRC/industry review and resolution of issues affecting

safe shutdown associated circuits and manual actions. As discussed above, these

issues have been placed into the licensees corrective action process.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed Entergys external flood analysis, flood mitigation procedures,

and design features to verify whether they were consistent with the IP2's design

requirements. The inspectors walked down selected external plant areas, including

areas for large on-site tanks that contain equipment important to safety. The inspectors

evaluated the condition and adequacy of mitigation equipment to assess whether the

flood protection design features were adequate and operable. During the walk downs,

the inspectors also evaluated whether there were any unidentified or unanalyzed sources

of flooding. The specific areas included:

  • Unit 2 Condensate Storage Tanks
  • Refueling Water Storage Tank

The inspectors reviewed Entergys flood mitigation procedures, flood alarm response

procedures, and selected preventive maintenance tasks and surveillance tests for the

sump pump in the service water strainer pit to evaluate whether component functionality

was routinely verified. In addition, the inspectors reviewed Entergys corrective action

program to verify whether previous flood related issues had been appropriately identified,

evaluated, and resolved. The following procedures were included in the review:

  • Individual Plant Examination for External Events (IPEEE) Section 6.0 External

Flooding

  • AOI 28.0.6, Nuclear Side (outside containment) Flooding
  • AOI 28.0.4, Flooding - Conventional Plant

b. Findings

No findings of significance were identified.

Enclosure

6

1R11 Operator Requalification Inspection

a. Inspection Scope

On March 3, 2003, the inspector observed the performance of an operating crew during

licensed operator re-qualification training. Specifically, the inspector observed simulator

as-found exams associated with lesson plan SS.700.032. The inspection was

conducted to assess the adequacy of the training, licensed operator performance,

emergency plan implementation, and the adequacy of the licensees critique.

b. Findings

No findings of significance were identified. The operating crew satisfactorily completed

the simulator scenario critical task. The crew critique and the evaluators assessment

were consistent with the inspectors observation of crew performance. Performance

issues associated with the crew involved abnormal operating instruction and emergency

operating procedure inconsistent usage and adherence, and recognition of applicable

Technical Specifications associated with an instrument failure. The crew initiated a

performance improvement plan to improve use of emergency operating procedure and

abnormal operating procedure attachments.

1R12 Maintenance Effectiveness

.1 22 Component Cooling Water

a. Inspection Scope

The inspectors evaluated Entergys work practices and preventive maintenance activities

for the 22 component cooling water (CCW) pump to assess the effectiveness of

maintenance activities. The inspectors reviewed the performance history of the 22 CCW

pump to assess the adequacy of the licensee's corrective actions and to evaluate

Entergys monitoring, evaluations, and disposition of issues in accordance with station

procedures and the requirements of 10 CFR 50.65, "Requirements for Monitoring the

Effectiveness of Maintenance." The inspectors reviewed the following documents

associated with the system design and licensing basis:

  • Maintenance Rule Basis Document for Component Cooling Water, Revision 1
  • System Health Report for the Component Cooling Water System, 4th quarter 2002
  • Design Bases Document for the Component Cooling Water System, Revision 0
  • System Engineering Procedure SE-303, Maintenance Rule Performance Criteria

Development/ Monitoring, Revision 0

  • UFSAR Section 9.3, Auxiliary Cooling System

01217

b. Findings

Enclosure

7

No findings of significance were identified.

.2 Boric Acid Transfer Pumps

a. Inspection Scope

The inspectors evaluated Entergys work practices and preventive maintenance activities

for the 21 and 22 boric acid transfer pumps (BATPs) to assess the effectiveness of

maintenance activities. The inspectors reviewed the performance history of the 21 and 22

BATPs to assess Entergys problem identification and the adequacy of the licensee's

corrective actions to evaluate whether monitoring, evaluations, and dispositioning of

issues were completed in accordance with station procedures and the requirements of

10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance." The

inspectors reviewed the following documents associated with system design and

licensing basis:

  • Maintenance Rule Basis Document for the Chemical and Volume Control System
  • System Health Report for the Chemical and Volume Control System, 4th quarter

2002

  • Design Basis Document for the Component Cooling Water System, Revision 0
  • System Engineering Procedure SE-303, Maintenance Rule Performance Criteria

Development/ Monitoring, Revision 0

  • UFSAR Section 9.2, Chemical and Volume Control System

2001-12846, IP2-2002-00441, and IP2-2002-02248

b. Findings

No findings of significance were identified.

Enclosure

8

1R13 Maintenance Risk Assessment and Emergent Work Activities

a. Inspection Scope

The inspector observed selected portions of emergent maintenance work activities to

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

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

work activities, took actions to minimize the probability of initiating events, and

maintained the functional capability of mitigating systems. The inspector observed and

discussed risk management with maintenance and operations personnel for the following

activities:

  • Surveillance test PT-Q55, during which pressurizer level bistable PC-457A failed

to trip (IP2-2003-00981)

  • Surveillance test PT-M21C (EDG 23 Load Test), during which the EDG load

rapidly increased to 2300 kW and then rapidly decreased to 0 kW (IP2-2003-

00570)

  • Emergent maintenance to replace the 22 steam generator level bistable (IP2-

2003-00788)

b. Findings

.1 23 Emergency Diesel Generator Load Oscillations

Introduction: A Green Finding was identified for ineffective corrective actions that resulted

in repetitive surveillance test failures of the 23 emergency diesel generator, (non-cited

violation of 10 CFR 50 Appendix B, Criterion XVI).

Description: The inspector identified that during a period between May 28, 2000 and

February 6, 2003, the licensee did not adequately correct load oscillations during

surveillance testing on the 23 emergency diesel generator.

On January 29, 2003, the 23 emergency diesel generator (EDG) was started for its

quarterly surveillance. While the 23 EDG was incrementally being loaded past 500kW,

the load rapidly increased to 2300 kW. The nuclear plant operator attempted to lower

the load using the governor raise/lower switch which resulted in the load rapidly

decreasing to 0 kW and the EDG tripped on reverse power. This issue was documented

in CR-IP2-2003-00570 and required a root cause analysis. Troubleshooting identified

that the motor operated potentiometer (MOP) may have had a dead spot, which could

explain why the 23 EDG load oscillations were intermittent. The MOP was replaced and

the 23 EDG was declared operable. Since failure analysis on the MOP would take

several weeks, the licensee increased the surveillance frequency on the 23 EDG to

provide confidence that the EDG was operable. On February 6, 2003, the 23 EDG again

experienced load oscillations during the surveillance testing.

Enclosure

9

Following the January 29, 2003 load oscillations, the inspectors reviewed the past work

orders (WOs) and condition reports (CRs) associated with the 23 EDG and identified

several CRs and WOs documenting load oscillations between May 2000 and

February 2003. The work orders documenting load issues associated with the 23 EDG

were:

and stayed at 2300 kW for about one minute. The EDG was manually unloaded

and tripped on reverse power. Corrective maintenance involved replacement of

the unit parallel relay; additionally, contact resistance on the unit/parallel switch

was checked.

was aborted due to load swings with the governor. Corrective maintenance

involved the removal and replacement of the motor operated potentiometer

(MOP).

or lower generator voltage, the EGB governor was replaced.

21C surveillance test due to unexpected response of the governor load control,

the EGA governor was replaced.

uncontrollably to 2300 kw and then decreased to 0 kW. Corrective maintenance

involved replacement of the motor operated potentiometer.

  • February 6, 2003, (IP2-200300758) load oscillations were observed on the 23

EDG and the licensee replaced the unit parallel relay and associated cables.

The review of the work history between May 2000 and February 2003 highlighted that the

major components that could cause the load swings were replaced at least once and, in

the case of the motor operated potentiometer, three times. In response to previous

condition reports, the licensee used industry operating experience to determine the most

probable cause of the load swings and justified continued EDG operation. The inspector

concluded that the responses to these condition reports did not include an evaluation of

the 23 EDG operating history. Condition Report IP2-2003-00570 required a full root

cause which included listing all the potential causes along with the past condition reports

and work history. This root cause was thorough and logical, and although no specific

cause of the load oscillations was determined, it provided confidence that the complete

spectrum of possibilities and the complete history were considered.

Analysis: The failure to correct the multiple generator load oscillations was more than

minor because the surveillance test failures associated with the load oscillations

impacted the availability of mitigating equipment. The inspectors also determined that

this finding was able to be assessed using the Significance Determination Process

because the finding was associated with the availability of a system or train in a

mitigating system. The inspectors conducted a Phase 1 Significance Determination

Process screening and determined that the failure to adequately address the cause of

multiple surveillance test failures of the 23 EDG due to load oscillations was of very low

risk significance because this finding did not represent an actual loss of safety function.

Enclosure

10

The inspectors confirmed that the last two surveillances that demonstrated automatic

start and loading of the 23 emergency diesel generator during accident conditions did not

result in load oscillations.

Enforcement: Criterion XVI of 10 CFR Part 50, Appendix B requires that in the case of

significant conditions adverse to quality, that measures shall assure that the cause of the

condition is determined and corrective actions taken to preclude repetition. The

licensees failure to adequately correct the load oscillations associated with the 23

emergency diesel generator between May 2000 and February 2003 was considered a

non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI in accordance with

Section VI.A.1 of the NRCs Enforcement Policy (NCV 50-247/03-03-02). This issue was

entered into the licensees corrective action program as IP2-2003-00570.

.2 Maintenance Instruction Deficiency

Introduction: A Green NCV was identified for inadequate emergent maintenance

instructions that subsequently resulted in operator action to restore pressurizer level and

pressure based upon de-energized control channel instruments.

Description: On February 7, 2003, inadequate emergent work instructions in work order

03-12284 resulted in an electrical short during replacement of the 22 steam generator

low level bistable. The electrical short caused the trip of circuit 10 on instrument bus 21.

Operators were subsequently challenged to restore pressurizer level and reactor coolant

system pressure due to the controlling channels failing low, based upon a loss of the

instruments 120 volt power source. Specifically, prior to operator actions to shift control

channels, reactor coolant system pressure decreased approximately 60 psig (resulting in

entry into TS 3.1.G.b) and pressurizer level increased 3% above the program band.

Analysis: This performance issue is more than minor since the operators were required

to take action to restore reactor coolant system pressure and pressurizer level to

preclude a reactor trip. The performance issue involved the initiating events cornerstone

in that it increased the likelihood of upset in plant stability; the attribute was human error

during the planning of an emergent work activity. In accordance with NRC Manual

Chapter 0609, Appendix A, this finding is considered to be of very low safety significance.

This conclusion is based upon the finding not contributing to the likelihood of a secondary

or primary LOCA initiator and not contributing to either a reactor trip or to mitigation

system unavailability.

Enforcement: The inadequate emergent maintenance instruction is a violation of 10 CFR

50 Appendix B, Criterion V, in that the instructions were not appropriate to the

circumstances. Specifically, on February 7, 2003, the instructions for work order 03-

12284 did not include information to minimize the likelihood of an electrical short near

energized reactor protection system bistables and did not have maintenance work

prerequisites to minimize plant transient impact, if the affected circuit were to be

inadvertently de-energized. The performance issue was considered a non-cited violation

of 10 CFR 50 Appendix B, Criterion V in accordance with Section VI.A.1 of NRCs

Enclosure

11

Enforcement Policy (NCV 50-247/03-03-03), and was documented in Entergys corrective

action program under CR No. IP2-2003-00788. Short-term corrective actions included

lessons-learned with both operations and instrument & control department personnel,

work planners review of the apparent cause report for IP2-2003-00788, and development

of a procedure to replace reactor protection system bistables.

1R14 Personnel Performance During Non-Routine Plant Evolutions and Events

.1 Heater Drain Pumps Tripping due to Leak Repair on the Heater Drain Tank Level

Column

a. Inspection Scope

On January 9, 2003, both heater drain tank pumps tripped causing the reactor operators

to decrease reactor power from 100% to 80% to maintain steam generator level. Prior to

the heater drain tank pumps tripping, a steam leak repair had just been completed on the

heater drain tank level transmitter (LT-1127). The inspectors observed operator

response, reviewed operator logs, interviewed cognizant personnel, and reviewed the

licensees root cause analysis report.

b. Findings

No findings of significance were identified.

.2 22 Main Condensate Pump Motor Failure

a. Inspection Scope

On March 3, 2003, at 8:42 p.m. the control room received a call from the on-shift

chemistry technician that the 22 condensate pump motor was on fire. The control room

sounded the fire alarm and dispatched the fire brigade. The fire was extinguished four

minutes later. Operators entered into AOI 21.1.1, Loss of Feedwater, and reduced

reactor power to 90 percent. Operators had to restore a number of non-safety related

pumps and fans in response to a voltage perturbation on the 6.9 KV bus which resulted

from a phase-to-phase fault within the 22 condensate motor. This event was

documented in Condition Report IP2-2003-1264.

The inspector reviewed the following documents in response to this plant transient:

  • Condensate motor maintenance work history and corrective action program

history

  • Protective relay test results for the 22 condensate motor breaker
  • Emergency Action Levels

The inspector evaluated equipment response, operator response to the transient, fire

brigade response, and short-term corrective actions taken by Entergy. The cause of the

Enclosure

12

motor failure was a phase-to-phase power supply cable fault. The fire was confined to

the cable insulation within the splice box where the fault originated.

b. Findings

No findings of significance were identified.

.3 Loss of Control Power to 22 Main Transformer Auxiliaries

a. Inspection Scope

On March 19, 2003, operators responded to a loss of control power to the 22 main

transformer auxiliaries. The cause of the loss of control power was a failure of the 480

volt/120 volt transformer. Operators entered into AOI 27.1.7 and reduced thermal power

to 78 percent. Transformer oil temperature reached 109 degrees centigrade (one degree

from a required turbine trip per AOI 27.1.7) before the operators installed a mechanical

blocking device on the auxiliary contactors and re-energized the transformer auxiliaries.

Transformer oil temperatures decreased to normal values after auxiliaries were restored.

The inspectors evaluated operator response to this event, reviewed the adequacy of AOI

27.1.7 guidance for coping with this transient, and verified short-term corrective action

involving the temporary alteration/blocking device (see report detail 1R23). Entergy

documented the following condition reports involving the loss of control power: IP2-2003-

1635; IP2-2003-1638; IP2-2003-1640; IP2-2003-1652; and IP2-2003-1673.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the below listed Condition Reports (CRs) and associated

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

component or system remained available without a significant degradation in

performance or unrecognized operability issue. The inspectors used Technical

Specifications, Updated Final Safety Analysis Report, and design basis documents, as

appropriate.

27.

valve PRV-5469.

Enclosure

13

secured.

pressure transmitters 1814B and 1814C are bent.

b. Findings

No findings of significance were identified.

1R17 Permanent Modifications

Station Auxiliary Transformer Load Tap Changer Modification

a. Inspection Scope

The licensee recently completed two preliminary calculations, FEX-00143-01, IP2 Load

Flow Analysis of the Electrical Distribution System, and FEX-00181-00, Evaluation of

the Load Tap Changer Operation of the Station Auxiliary Transformer Following Fast-

Transfer. These preliminary calculations showed that under certain expected grid

voltage conditions, coincident with a plant event which required safety injection (SI), the

safety buses at the plant could separate from the off-site power supplies. During normal

plant operation, four of the 6.9 kV buses are supplied by the unit auxiliary transformer

(UAT). With a unit generator trip (30 seconds after the SI initiation), the supply for these

four buses would be fast-transferred to the station auxiliary transformer (SAT). The SAT

has an automatic load tap changer (LTC) which maintains the secondary voltage at 7.1

kV. With the existing LTC operation, the fast transfer could cause the secondary voltage

to drop below the degraded voltage setpoint for more than 10 seconds, resulting in a

separation of the safety buses from the off-site power. This issue was documented in

CR 2002-07918, dated August 21, 2002. The licensee found that the design basis

calculation (EGP-001100-00) which evaluated compliance with degraded grid

requirements and compliance with 10 CFR 50, Appendix A, General Design Criteria 17,

had a number of non-conservative assumptions. For example, the calculation did not

account for: the fast bus transfer 30 seconds after a safety injection signal, instrument

tolerances for the degraded voltage relays, and the neutral position of the LTC.

The licensee initiated design change package (DCP) 02-2-005, SAT Load Tap Changer

SI Modification, to improve the SAT secondary voltage response following an SI

initiation. The design of this modification was completed on October 3, 2002, and the

modification was to be implemented during the November 2002 outage. The

modification involved the addition of a bypass circuit (for a duration of 40 seconds only) in

the LTC control circuitry that is activated by the SI signal. The purpose of the

modification was to quickly raise, following the two second time delay of the LTC and

within the time limit of 40 seconds, the SAT secondary voltage to a maximum of 7350 V

or to the highest step of the LTC before the fast-transfer takes place (30 seconds after SI

initiation). At the time of the inspection (week of November 4, 2002), the relay box of the

Enclosure

14

bypass circuit was installed, field wiring was in-progress, and the pre-installation

calibrations of the voltage sensing and time delay relays were completed.

The inspector selected DCP 02-2-005 for review because preventing a degraded voltage

condition at the safety-related buses contributes significantly to the prevention of core

damage. The inspector reviewed the design features (including voltage settings and time

delay settings of the voltage sensing and time delay relays) to verify that the design

requirements were met. The inspector also reviewed the modified schematic diagrams,

with the added bypass circuit to the LTC control circuitry, to verify the adequacy of the

new design. In addition, the inspector reviewed the bench and functional testing

requirements and verified that appropriate acceptance criteria were specified.

b. Findings

At the end of the inspection period, Entergy was in the process of completing the

reconstitution of the electrical calculations to support the degraded grid analysis. Entergy

has open corrective action assignments to evaluate the implications on past operability of

the system and to evaluate reportability per 10 CFR 50.73. The inspector considers this

issue unresolved, pending NRC review of the final electrical calculations and implications

on historical plant risk of off-site power source reliability. (URI 50-247/03-03-04)

1R19 Post Maintenance Testing

a. Inspection Scope

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 IP2s Individual Plant Examination. The regulatory references for the inspection

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

Inspection, Test, and Operating Status. The following testing activities were evaluated:

strainer functions properly, performed on January 21, 2003.

feedwater pump, performed on January 10, 2003.

February 26, 2003, and WO-IP2-00-13327, preventive maintenance on the boric

acid transfer pump 22 outlet to boric acid filter stop, performed in March 2001.

Enclosure

15

and IP2-03-04664, black start diesel tripped on high cooling water temperature

during PT-M38A, performed on March 21 and 22, 2003.

water cooling pump, performed on March 25, 2003.

the 22 battery charger (CR 2003-00732), performed on February 4, 2003.

b. Findings

Introduction: A Green NCV was identified for an inadequate post-maintenance test on the

22 boric acid transfer pump outlet to the boric acid filter stop (valve No. 370) in 2001.

Description: A self-revealing event was identified on February 26, 2003, when operators

observed no boric acid flow to the reactor core via the 22 boric acid transfer pump

(BATP) using blended makeup. During preventive maintenance activities in March 2001,

the post-work test on valve No. 370 failed to identify that an internal plate to the valves

diaphragm was installed upside down. The consequence of the finger plate installed

upside down resulted in the diaphragm being cut and subsequently causing the valve to

hydraulically lock. This degraded valve condition was not identified during surveillance

testing because flow does not pass through the valve during periodic testing.

Analysis: The performance deficiency is considered more than minor because the

improperly installed valve plate was not identified during the post work test and adversely

impacted the availability of a single train of emergency boration. This finding is

considered to be of very low risk significance in accordance with NRC MC 0609

Appendix A, since the emergency boration safety function was not lost due to this

performance issue.

Enforcement: This finding is a violation of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, in that the post-work test prescribed in work

order No. IP2-00-13327 did not adequately verify that the valve was properly reinstalled

after preventive maintenance. The performance issue was considered a non-cited

violation of 10 CFR 50 Appendix B, Criterion V in accordance with Section VI.A.1 of

NRCs Enforcement Policy (NCV 50-247/03-03-05), and was documented in Entergys

corrective action program under CR No. IP2-2003-01121.

Enclosure

16

1R22 Surveillance Testing

a. Inspection Scope

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) the 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 Indian Point 2 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 Operating Status, Criterion XI, Test Control, and Technical

Specifications 6.8.1.a. The following test activities were reviewed:

  • PT-Q48, AMSAC Logic, revision 5, performed on January 22, 2003

January 30, 2003

performed on February 12, 2003

March 11, 2003

  • PT-Q29C, 23 Safety Injection Pump, revision 13, performed on February 21,

2003.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope (71111.23)

The inspector reviewed the below listed temporary alteration (TA) to ensure that: the TA

was appropriately evaluated by Entergy in accordance with 10 CFR 50.59; the TA did not

adversely impact the safety function or operation of the system/component modified; and

that the TA was appropriately installed in accordance with administrative procedure ENN-

DC-136, Temporary Alteration Control. One minor drawing issue was identified by the

inspector and entered into the licensees corrective action process for resolution. The

following TA was reviewed:

b. Findings

Enclosure

17

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

During a combined in-office and on-site inspection during January 6 - 29, 2003, the

inspectors reviewed recent changes in the EP area. Specifically, Unit 2 and Unit 3

emergency plans were combined into a common Emergency Plan. Also, certain

implementing procedures for the Emergency Operation Facility and the Joint News

Center are now common to both units. A thorough review was conducted of aspects of

the plan related to the risk significant planning standards (RSPS), such as classifications,

notifications, and protective action recommendations. A general review was conducted

for non-RSPS portions. These changes were reviewed against 10 CFR 50.54(q) to

ensure that the changes did not decrease the effectiveness of the plan, and that the

changes continued to meet the standards of 10 CFR 50.47(b) and the requirements of

Appendix E. For areas for which minor clarifications would enhance the new Emergency

Plan, the licensee generated CRs. All of the changes made to the Emergency Plan or

associated implementing procedures are subject to future inspections to ensure that the

result of the changes continue to meet NRC regulations.

b. Findings

No findings of significance were identified.

1EP6 Emergency Plan Drills

a. Inspection Scope

On February 26, 2003, the inspectors observed Entergys emergency response

organization during an announced emergency preparedness training drill at Indian Point

Unit 2. The simulated emergency included the activation of the Operations Support

Center (OSC), the Technical Support Center (TSC) and Emergency Operations Facility

(EOF) after an Alert (simulated) was declared by the control room operators. The control

room simulator was used for the exercise, in addition to the OSC, TSC, EOF, and the

Joint News Center (JNC).

The inspectors observed the conduct of the exercise in the control room simulator, OSC,

TSC, and EOF. The inspectors assessed licensed operator and the licensees adherence

to emergency plan implementation procedures, and their response to simulated

degraded plant conditions to identify weaknesses and deficiencies in classification,

notification, and protective action recommendation activities. In addition to the drill, the

inspectors observed the licensees controller critique to evaluate the licensees self-

identification of weaknesses and deficiencies. The inspectors compared the licensees

identified findings against their observations. The inspectors' review included the

following documents and procedures:

Enclosure

18

  • Implementing Procedure (IP)-1002, Emergency Notification and Communication
  • IP-1030, Emergency Operations Facility
  • Operation Support Center Drill Log

2003-01350, IP2-2003-01349, and IP2-2003-01347

b. Findings

No findings of significance were identified.

2. RADIATION SAFETY

Cornerstone: Occupational Radiation Safety (OS) and Public Safety (PS)

2OS1 Access Control to Radiologically Significant Areas

a. Inspection Scope

The inspector reviewed radiological work activities and practices and procedural

implementation during tours and observations of the facilities. Additionally, the inspector

reviewed procedures, records, and other program documents to evaluate the

effectiveness of access controls to radiologically significant areas. Further, the inspector

observed activities at the routine radiologically-controlled-area (RCA) access control point

(HP-1) on several occasions to verify compliance with requirements for RCA entry and

exit, dosimetry placement, and issuance and use of electronic dosimeters.

On February 24, 2003, the inspector discussed the status of the radiation protection

organization and procedures for Units 2 and 3 with the radiation protection manager

(RPM). The inspector also discussed the radiological work activities and dose

projections for the upcoming week for each unit.

On February 25, 2003, the inspector reviewed the radiation work permit (No. 032028)

used for non-outage containment entries at Unit 2. Also, the inspector discussed with the

RPM the methods for the segregation of high level and low level dry active radioactive

waste in work areas during outages with radioactive waste personnel and radiation

protection technicians from both units. In addition, the inspector discussed survey

frequencies and posting and their use for briefings of radiation workers with a Unit 2

radiation protection supervisor.

On February 26, 2003, the inspector toured and observed work activities in selected

portions of the fuel handling building and the chemical systems building in Unit 1,

including the area in the sphere annulus area where the pipe from the north curtain drain

Enclosure

19

was located. Also, the inspector toured and observed work activities in various

elevations in the primary auxiliary building in Unit 2. During these tours and

observations, the inspector reviewed, for regulatory compliance, the performance of the

radiation workers and radiation protection technicians and the posting, labeling,

barricading, and level of radiological access control for locked high radiation areas

(LHRAs), high radiation areas (HRAs), radiation and contamination areas, and

radioactive material areas. The inspector reviewed and observed work activities for

compliance with the radiation work permit (RWP) requirements.

The inspector performed a selective examination of procedures, records, and other

program documents (reference the List of Documents Reviewed Attachment) to evaluate

the adequacy of radiological controls. This review was against criteria contained in 10

CFR 19.12, 10 CFR 20 (Subparts D, F, G, H, I, and J), Technical Specifications, and site

procedures.

b. Findings

No findings of significance were identified.

2OS2 ALARA Planning and Controls

a. Inspection Scope

The inspector reviewed the effectiveness of Entergys program to maintain occupational

radiation exposure as low as is reasonably achievable (ALARA).

On February 24, 2003, the inspector discussed the Unit 2 and 3 cumulative dose results

for 2002, and the cumulative dose estimates for 2003, with the technical support

manager. Further, the inspector discussed the integration of the ALARA planning

process into the stations work planning and control process with an ALARA radiological

engineer.

On February 26, 2003, the inspector examined the pre-job ALARA review for 2R15 RWP

No. 025226, involving outage valve work and the in-progress and post-job ALARA

reviews for the same job, to assess the effectiveness of the radiological controls. The

inspector also reviewed the post-job ALARA review for 2R15 RWP No. 025206, involving

outage radiological waste support.

The inspector performed a selective examination of procedures, records, and documents

(reference the List of Documents Reviewed Attachment) for regulatory compliance and

for adequacy of control of radiation exposure. This review was against criteria contained

in 10 CFR 20.1101 (Radiation protection programs), 10 CFR 20.1701 (Use of process or

other engineering controls), and site procedures.

b. Findings

No findings of significance were identified.

Enclosure

20

2OS3 Radiation Monitoring Instrumentation and Protective Equipment

a. Inspection Scope

The inspector reviewed the program for health physics instrumentation to determine the

accuracy and operability of the instrumentation.

During the plant tour on February 26, 2003, described in Section 2OS1 of this report, the

inspector reviewed field instrumentation utilized by health physics technicians and plant

workers to measure radioactivity and radiation levels including: portable field survey

instruments; hand-held contamination frisking instruments; continuous air monitors;

installed radiation monitors; whole body friskers; portal monitors; area monitors, and

process monitors. The inspector conducted a review of the instruments observed in the

toured areas, specifically for verification of current calibrations, appropriate source

checks, and proper function.

The inspector performed a selective examination of documents (reference the List of

Documents Reviewed Attachment) for regulatory compliance and adequacy. This review

was against criteria contained in 10 CFR 20.1501, 10 CFR 20 Subpart H, Technical

Specifications, and site procedures.

b. Findings

No findings of significance were identified.

2PS1 Gaseous and Liquid Effluents

a. Inspection Scope

The inspector reviewed the following documents to evaluate the effectiveness of the

licensees radioactive gaseous and liquid effluent control programs. The requirements

for radioactive effluent controls are specified in the Technical Specifications and the

Offsite Dose Calculation Manual (TS/ODCM):

  • the 2001 Radiological Annual Effluent Release Report, including projected public

dose assessments;

  • review of the current ODCM (Revision 6, October 28, 1999), including technical

justifications for Revision 7;

  • selected 2002 analytical results for charcoal cartridge, particulate filter, and noble

gas samples;

  • implementation of the compensatory sampling and analysis program when the

effluent radiation monitoring system (RMS) was out of service;

  • selected 2002 radioactive liquid and gaseous release permits;
  • associated effluent control procedures, including analytical laboratory procedures;
  • calibration results for chemistry laboratory measurement equipment (gamma and

liquid scintillation counters);

Enclosure

21

  • implementation of the measurement laboratory quality control program, including

effluent intra-laboratory and inter-laboratory comparisons and control charts;

  • the 2001 and 2002 NQA Audits (Audit Nos. 01-AR-21-RP, August 1-8, 2001 and

02-AR-14-RP, April 11-17, 2002) of the implementation of the radioactive liquid

and gaseous effluent control program and the ODCM;

  • Radiation Monitoring System Reliability Plan;
  • the most recent Channel Calibration and Channel Functional Test results for the

radioactive liquid and gaseous effluent radiation monitoring system (RMS) and its

flow measurement devices as listed in Tables 4.10-2 and 4.10-4 of the Technical

Specifications (TS):

Unit 1 RMS:

6 Service/River Water Liquid Radiation Monitor (R-51);

6 Liquid Discharge Radiation Monitor (R-54);

6 Secondary Boiler Blowdown Effluent Line (R-52);

6 Sphere Foundation Sump Discharge Monitor (R-62); and

6 Stack Vent Noble Gas Monitor (R-60).

Unit 2 RMS:

6 Waste Disposal Liquid Effluent Line (R-48);

6 Component Cooling Water Radiation Monitor (R-47);

6 Steam Generator Blowdown Effluent Line (R-49);

6 Service Water System Effluent Line Monitors (R-46/53);

6 Component Cooling Service Water Heat Exchangers (R-39/40);

6 Plant Vent Noble Gas Monitors (R-44 and R-27); and

6 Large Gas Decay Holding Tank Monitor (R-50).

Enclosure

22

Units 1 & 2 Flow Rate Measurement Devices:

6 Stack Vent Flow Rate Monitor;

6 Plant Vent Flow Rate Monitor;

6 Liquid Effluent Line Flow Rate Monitor; and

6 Steam Generator Blowdown Effluent Line.

  • the most recent surveillance testing results for the following air treatment systems

listed in the following TS:

6 TS 4.5.D Containment Fan Cooler System (air flow tests for five Fan

Cooler Units);

6 TS 4.5.E Control Room Air Filtration System (system flow rate,

laboratory test in accordance with ASTM D3803-1989, in-

place testings for HEPA and charcoal filters, pressure drop

test, visual inspection);

6 TS 4.5.F Fuel Storage Building Air Filtration System (system flow

rate, laboratory test in accordance with ASTM D3803-1989,

in-place testings for HEPA and charcoal filters, pressure

drop test, visual inspection); and

6 TS 4.5.G Post-Accident Containment Venting System (system flow

rate, laboratory test in accordance with ASTM D3803-1989,

in-place testings for HEPA and charcoal filters, pressure

drop test, visual inspection).

The inspector also toured and observed the following activities to evaluate the

effectiveness of the licensees radioactive gaseous and liquid effluent control programs:

  • availability of radioactive liquid/gaseous effluent RMS to determine the equipment

material condition; and

  • operability of air cleaning systems to determine the equipment material condition.

b. Findings

No findings of significance were identified.

2PS2 Radioactive Material Processing and Transportation

a. Inspection Scope

The inspection consisted of a review of Condition Report IP2-2003-00771, identified in

the Corrective Action Program (CAP), for the appropriateness and adequacy of event

categorization, immediate corrective action, corrective action to prevent recurrence, and

timeliness of corrective action.

b. Findings

Enclosure

23

Introduction. A Green self-revealing non-cited violation (NCV) of 10 CFR 71.12, which

addresses general licenses for NRC-approved packages, was identified for failure to

comply with the package procedures relating to the use and maintenance of the

packaging.

Description. Condition Report IP2-2003-00771 (dated February 6, 2003), documented

that a shipment of filters, packaged in a CNS 8-120 B cask (an NRC-approved Type B

shipping container), left Indian Point 2 on February 3, 2003, and arrived at a

consolidation facility in South Carolina on February 5, 2003. During the unloading

process, facility personnel discovered that a bolt, that was to be installed in the primary

lids air pressure test port, in accordance with procedure TR-OP-035, Handling

Procedure for CNS 8-120 B, was missing. The bolt had not been installed during the re-

assembly of the cask for shipment.

Analysis. This finding constituted a performance deficiency in that it resulted in a

requirement not being met that was reasonably within Entergys ability to foresee and

correct and that should have been prevented. This finding was more than minor in that

the finding was associated with the Public Radiation Safety Cornerstones attribute of

procedures for transportation packages. The finding affected the associated cornerstone

objective to ensure adequate protection of public health and safety from exposure to

radioactive materials released into the public domain. Specifically, a

procedure/document, relating to the preparation, use, and maintenance of an NRC-

approved Type B packaging was not properly implemented, and the package was

shipped on a public highway. Following the Public Safety Significance Determination

Process, the issue was determined to be of very low safety significance in that the finding

did not involve exceeding transportation radiation limits, there was no breach of the

package during transit, and it was a Certificate of Compliance (CoC) maintenance/use

performance deficiency.

Enforcement. 10 CFR 71.12(a) and (c), together with paragraphs 9(i) and 9(iii) of the

NRC Certificate of Compliance No. 9168 and procedure TR-OP-035, Handling

Procedure for CNS 8-120 B, require that a bolt shall be installed and torqued into place

in the primary lids air pressure test port prior to shipment. Contrary to these

requirements, on February 3, 2003, a bolt was not installed and torqued into place in the

primary lids air pressure test port prior to shipment.

Entergy actions associated with this finding are documented CR IP2-2003-00771.

Because this self-revealing violation was of very low safety significance and because

Entergy entered these issues into its corrective action program, this violation is being

treated as a self-revealing NCV, consistent with Section VI.A of the NRC Enforcement

Policy. (NCV 50-247/03-03-06)

Enclosure

24

4. OTHER ACTIVITIES (OA)

4OA1 Performance Indicator Verification

The inspector reviewed the licensees performance indicator (PI) data collecting and

reporting process as described in procedure SAO-114, Preparation of NRC and WANO

Performance Indicators. The purpose of the review was to determine whether the

methods for reporting PI data are consistent with the guidance contained in Nuclear

Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator

Guidelines, Revisions 1 and 2. The inspection included a review of the indicator

definitions, data reporting elements, calculation methods, definition of terms, and

clarifying notes for the performance indicators. Plant records and data were sampled

and compared to the reported data. The inspector reviewed the licensees actions to

address and satisfactorily resolve discrepancies in the performance indicator data.

.1 Reactor Coolant System Leakage

a. Inspection Scope

The inspector reviewed the performance indicator (PI) for reactor coolant system (RCS)

leakage for the period from January - December 2002. This PI remained in the Green

band. The inspector reviewed the completed SOP 1.7 RCS leak rate surveillance

determinations to verify the adequacy of the reported PI data. The inspector observed

licensee performance of the leak rate surveillance on February 12, 2002. The licensees

corrective action program records were also reviewed to determine if any problems with

the collection of PI RCS leakage data had occurred. The inspectors compared the PI

data against the guidance contained in NEI 99-02.

b. Findings

No findings of significance were identified.

.2 Scrams Per 7,000 Critical Hours

a. Inspection Scope

The inspector reviewed Entergys PI data for Unplanned Scrams Per 7,000 Critical Hours

to verify whether the PI data was accurate and complete. The PI remained in the green

band for the four quarters of 2002. The inspector reviewed operator logs, licensee event

reports, and monthly operating reports to compare PI data reported by the licensee. The

inspectors compared the PI data against the guidance contained in NEI 99-02.

b. Findings

No findings of significance were identified.

.3 Residual Heat Removal System Unavailability

Enclosure

25

a. Inspection Scope

The inspector reviewed Entergys Performance Indicator (PI) data for Residual Heat

Removal (RHR) Safety System Unavailability to verify whether the PI data was accurate

and complete. The inspectors compared the PI data reported by the licensee to

information gathered from the control room logs, condition reports, and work orders for

the four quarters of 2002. In addition, the inspectors interviewed the system engineers.

The inspectors compared the PI data against the guidance contained in NEI 99-02.

b. Findings

No findings of significance were identified.

.4 Emergency AC Power System Unavailability

a. Inspection Scope

The inspector performed a review of the 2002 quarterly performance indicator data

submitted by the licensee for the safety system unavailability of the emergency AC power

system (emergency diesel generators) to determine its accuracy and completeness. The

inspector researched the control room operating logs and the condition reporting system

to identify when the emergency diesel generators were out of service during the period of

review. The control room operating logs were also reviewed to determine the number of

hours the EDGs were required to be operational. The inspector used the guidance

provided in NEI Report 99-02 to calculate the ratio of the number of hours the emergency

AC power system was unavailable to the number of hours the emergency AC power

system was required.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Baseline Procedure Problem Identification and Resolution Review

a. Inspection Scope

The inspection included a review of the following issues identified in the corrective action

program for the appropriateness and adequacy of event categorization, immediate

corrective action, corrective action to prevent recurrence, and timeliness of corrective

action: Condition Report Nos. IP2-2002-10106 and -10795 and 2003-00328, -00400, -

00401, -00751, -00771, -00826, 2001-09250, 2001-09604, 2001-12738, 2001-11035,

2001-02811, 2001-11958, 2001-11056, 2002-11130, 2001-07475, 2001-11614, 2002-

01208, 2002-02184, 2002-08402, 2002-11130, 2001-09250, 2001-09604, 2001-12738,

2001-11035, 2001-02811, 2001-11958, 2001-11056, 2002-11130, 2001-07475, 2001-

11614, 2002-01208, 2002-02184, 2002-08402, 2002-00504, 2002-03729,2002-

Enclosure

26

03245,2002-10605, 2002-05578, 2002-50779, 2002-04353, 2002-05578, 2002-07617,

2002-10071, and 2002-10605

b. Findings

No findings of significance were identified.

.2 Adverse Trend in Residual Heat Removal Boron Concentration, IP2-2002-03035

a. Inspection Scope

The inspector selected CR No. IP2-2002-03035 for detailed review. The condition report

was associated with an adverse trend (decreasing) in residual heat removal (RHR) boron

concentration. The CR was reviewed to ensure a complete and accurate identification of

the issue, an appropriate evaluation was performed, and appropriate corrective actions

were specified and prioritized. The inspector evaluated the report against the

requirements of the licensees corrective action process (CAP) as delineated in Site

Administrative Procedure ENN-LI-1102, Revision 2, Corrective Action Process.

b. Findings

There were no findings associated with the sample CR reviewed; however, the inspector

found that the licensee had not confirmed that the adverse trend was corrected. The

licensee performed an apparent cause evaluation and concluded that the most likely

source of the leakage into the RHR system and resulting boron dilution was occurring

through valves 730 and 731. The apparent cause evaluation was performed through a

review of past valve leakage history in the RHR system. Based on this determination,

preventive and corrective maintenance was performed on these valves and the CR was

closed. The sample for boron analysis is taken from the system when the RHR pumps

are run during their scheduled surveillance test to assure thorough mixing of the water

within the system. The inspector determined that the adequacy of the apparent cause

determination and the success of corrective actions cannot be confirmed until

subsequent quarterly pump testing is completed. Since the apparent cause evaluation

appeared to be reasonable and the corrective actions were timely, relative to the

significance of the condition, no violation of regulatory requirements was identified.

Enclosure

27

.3 Loss of Security Perimeter Lighting, IP2-2002-11628 and 2002-11629

a. Inspection Scope

The inspector selected CR Nos. IP2-2002-11628 and -11629 for a detailed review. The

CRs were associated with a loss of perimeter lighting on December 27, 2002. The

inspector observed that Entergys short-term compensatory actions were consistent with

the Security Contingency Plan, observed short-term corrective actions to repair and

restore the lighting, and confirmed long-term work orders existed to improve the reliability

and material condition of the perimeter lighting.

b. Findings

No findings of significance were identified.

.4 Communication failures between the Emergency Operations Facility computer system

and the field sirens, IP2-2003-01107

a. Inspection Scope

The inspectors selected CR No. IP2-2003-01107 for detailed review. The CR was

associated with communication failures between the emergency operations facility (EOF)

computer system and the field sirens that alert and notify the public in case of an event at

Indian Point. The report was reviewed to ensure that the full extent of the issue was

identified, an appropriate evaluation was performed, and that appropriate corrective

actions were specified and prioritized. The inspectors evaluated this CR against the

requirements of 10 CFR 50.47, Emergency Plans, and Appendix E, Emergency

Planning and Preparedness for Production and Utilization Facilities.

b. Findings

No findings of significance were identified.

.5 Fundamental Improvement Plan Effectiveness Reviews

a. Background and Scope

In January 2002, Entergy provided the NRC with a copy of the fundamental improvement

plan (FIP) consistent with the NRCs action matrix for a multiple degraded cornerstone

facility. The fundamental improvement plan documented corrective action plans and

effectiveness reviews associated with five key areas involving human performance,

design control/licensing basis, equipment performance/work management, problem

identification and resolution, and licensed operator performance. By letter dated

August 28, 2002, the NRC removed Indian Point Unit 2 from the repetitive multiple

degraded cornerstone column of the action matrix. Entergy continued to implement

actions associated with the FIP until the end of calendar year 2002.

Enclosure

28

The inspection scope was to review the eight effectiveness reviews conducted within the

FIP. The effectiveness reviews included: management observation of work activities;

operator burden and work-down curve for temporary alterations; review of the design

basis initiative project; optimization of the preventive maintenance program; corrective

actions in monitoring the work control process; equipment reliability actions; work

management self-assessments; and corrective action effectiveness reviews for condition

reports.

The inspector reviewed the FIP expectation, reviewed the completed effectiveness

evaluations, and discussed the evaluations with individuals assigned to perform the

reviews. The inspector compared the results and conclusions of the individual

effectiveness review with applicable performance metrics maintained by Entergy and

using past applicable NRC assessments in performance (inspection report findings and

ROP-3 end-of-cycle assessments).

b. Findings

No findings of significance were identified. The inspector concluded that selected

effectiveness reviews were not consistently self-critical. For example, the effectiveness

review for the design basis initiative project primarily focused on the quality of action

plans and efficiencies of plan implementation instead of the quality of the output products

and the amount of use of this information by design and system engineering staffs. The

NRCs evaluation also found that the work control effectiveness reviews did not explore

the quality of post-work tests, but rather highlighted processing problems associated with

post-work testing.

The NRC noted that the 2003 Indian Point Business plan provided adequate actions to

support improvements in the five key areas from the FIP. Further, self-assessments are

currently part of the business plan and areas within the plan focus on departmental self-

assessments and monitoring the quality of those assessments through a self-

assessment review board.

4OA3 Event Follow-up

.1 Licensee Event Report (LER) 2002-002-00 Restoration of Previously Isolated Portion of

Weld Channel and Containment Penetration Pressurization System,

(Closed) Licensee Event Report (LER) 2002-002-00, Restoration of Previously Isolated

Portion of Weld Channel and Containment Penetration Pressurization System, dated

August 7, 2002. On June 8, 2002, the licensee confirmed through testing that a

previously retired (because of supposed leakage) section of Zone W-11 of the weld

channel and containment penetration pressurization system (WCCPPS) was leak-tight

and should be restored to an operable status. The licensee concluded that the cause of

the premature retirement of this section of Zone W-11 was an inadequate leak test of the

subject weld channel and a poor assumption that leakage was in a section of the weld

channel embedded in concrete and, therefore, not capable of being repaired.

Enclosure

29

In addition to the broad corrective action taken under the FIP, dated January 25, 2002, to

address the human performance weaknesses which contributed to this event, the

operations manager deleted the operations department troubleshooting procedure (DAD-

40) in favor of the work control departments procedure governing troubleshooting and

repairs. The work control department procedure implements a more thorough planning,

review, approval, and closeout process which ensures a higher probability of a

satisfactory troubleshooting result. This LER is closed.

4OA5 Review of Institute of Nuclear Power Operations (INPO) Evaluation Report

The inspectors reviewed the final report of an INPO Evaluation conducted in February

2002. The inspectors identified no new findings of significance.

4OA6 Meetings, Including Exit

The inspectors met with Indian Point 2 representatives at the conclusion of the inspection

on April 9, 2003. At that time, the purpose and scope of the inspection were reviewed,

and the preliminary findings were presented. The licensee acknowledged the preliminary

inspection findings.

The inspector asked the licensee whether any materials examined during the inspection

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

inspection.

ATTACHMENT: SUPPLEMENTAL INFORMATION

Enclosure

1

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Entergy:

W. Axelson Support Supervisor

M. Dampf Health Physics Manager

R. Deschamps Radiological Protection Superintendent

R. Decensi Technical Support Manager

R. Fucheck HP Supervisor

D. Gately Radiation Protection Coordinator

R. LaVera Radiological Engineer

R. Majes Radiological Engineer

R. Richards HP Supervisor

R. Rodino Radiological Engineer

W. Scholtens Waste Management Contractor

R. Solanto HP Supervisor

J. Stewart HP Supervisor

R. Tagliomonte Waste Management Supervisor

N. Azevedo ISI Supervisor

W. Axelson Support Supervisor

T. Burns Environmental Supervisor

J. Comiotes Director, Nuclear Safety Assessment

L. Cortopassi IP3 Training Manager

F. Dacimo Vice-President

M. Dampf Health Physics Manager

S. Davis IP2 Licence Operator Requalification Training Supervisor

R. Decensi Technical Support Manager

R. Deschamps Radiological Protection Superintendent

J. DeRoy General Manager Plant Operations, IP3

K. Finucan Emergency Planning Staff

K. Finvean Reactor Vessel Head Inspection, Assistant Project Manager

R. Fucheck HP Supervisor

D. Gately Radiation Protection Coordinator

M. Gillman IP3 Operations Manager

L. Glander Dosimetry Supervisor

J. Goebel Reactor Vessel Head Inspection, Project Manager

F. Inzirillo Manager Emergency Planning

T. Jones Nuclear Safety and Licensing

R. LaVera Radiological Engineer

R. Majes Radiological Engineer

J. McCann Nuclear Safety and Licensing Manager

F. Mitchell HP Supervisor

D. Pace VP - Engineering - ENN

J. Perrotta Quality Assurance Manager

Attachment

Attachment (contd) 2

R. Penny Manager, Engineering Programs

R. Richards HP Supervisor

K. Richett HP Technician

R. Rodino Radiological Engineer

R. Sachatello Radiological Consultant

C. Schwarz General Manager, IP2 Plant Operations

G. Schwartz Chief Engineer

H. Salmon Quality Assurance Director

M. Smith Director of IP3 Engineering

R. Solanto HP Supervisor

S. Stevens HP Technician

J. Stewart HP Supervisor

D. Sullivan-Weaver Emergency Planning Staff

J. Tuohy Design Engineering Manager

J. Wheeler Site Training Manager

F. Wilson Superintendent, Operations Training

M. Wilson Emergency Planning Staff

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Closed

LER 50-247/ 2002-002-00 Restoration of previously isolated portion of weld channel and

containment penetration pressurization system

Open/Closed

50-247/03-03-02 NCV Ineffective corrective actions associated with the 23 EDG load

swings between May 2000 and February 2003

50-247/03-03-03 NCV Improper emergent work package instructions for 22 steam

generator level bistable replacement

50-247/03-03-05 NCV Post-work test inadequate for 22 boric acid transfer pump boric

acid filter stop valve

50-247/03-03-06 NCV Failure to comply with packaging procedures

Opened

50-247/03-03-01 URI Lack of cable separation in fire areas F and J, postulated fire

compromising associated circuits.

50-247/03-03-04 URI Electrical calculation reconstitution to support offsite power design

basis (SAT load tap changer).

Attachment

Attachment (contd) 3

LIST OF DOCUMENTS REVIEWED

Sections 1EP4, Emergency Action Level and Emergency Plan Changes

Emergency Plan for Indian Point Unit Nos 1 and 2, Rev 01-02a

Indian Point 3 Emergency Plan, Rev 46

Indian Point Energy Center Emergency Plan, Rev 02-01

IP-EP-251, Alternate Emergency Operations Facility, Rev 0

IP-EP-255, Emergency Operations Facility Management and Liaisons, Rev 1, 2

IP-EP-310, Dose Assessment, Rev 0

IP-EP-410, Protective Action Recommendations, Rev 0

IP-EP-510, Meteorological, Radiological & Plant Data Acquisition System, Rev 0

IP-EP-520, Modular Emergency Assessment & Notification System (MEANS), Rev 0

IP-EP-610, Emergency Termination and Recovery, Rev 0

IP-EP-620, Estimation of Total Population Exposure, Rev 0

IC/EALs, Initiating Conditions & Emergency Action Levels, Rev 9 (IP3)

IP-1001, Determining the Magnitude of Release, Rev 17, Void (IP3)

IP-1002, Emergency Notification and Communication, Rev 27, 28 (IP2)

IP-1003, Obtaining Meteorological Data, Rev 18, Void (IP3)

IP-1004, MIDAS Computer System, Rev 16, Void (IP3)

IP-1010, Central Control Room, Rev 6, 7, 8 (IP2)

IP-1013, Protective Action Recommendations, Rev 8, (IP2)

IP-1015, Radiological Monitoring Outside the Protected Area, Rev 10 (IP2)

IP-1017, Protective Action Recommendations for the Offsite Population, Void, Rev 13

(IP3)

IP-1019, Coordination of Corporate Response, Rev 11 (IP2)

IP-1021, Manual Update, Readout & Printout of Proteus Plant Parameter Data, Canceled

(IP2)

IP-1023, Operation Support Center, Rev 19 (IP2)

IP-1026, Emergency Data Display, Rev 1 (IP2)

IP-1027, Personnel Accountability Rev 17 (IP2)

IP-1027, Emergency Personnel Exposure, Rev 13, (IP3)

IP-1030, Emergency Operations Facility, Rev 8 (IP2)

IP-1030 Emergency Operations Facility, Rev 7 (IP2)

IP-1035, Technical Support Center, Rev 17 (IP2)

IP-1050, Security, Rev 4 (IP2)

IP-1050, Accountability, Rev 28 (IP3)

IP-1054, Search and Rescue Teams, Rev 11 (IP3)

IP-2001, ED, POM, Shift Managers Procedure, Rev 16, 17 (IP3)

IP-2003 CR Watch Chemist, Rev 6 (IP3)

IP-2200, Emergency Activation of the Operations Support Center, Rev 7 (IP3)

IP-2201 OSC Manager, Rev 9 (IP3)

IP-2204, OSC Team Leader, Rev 3 (IP3)

IP-2209, OSC HP Technician, Rev 5

IP-2301, Emergency Director, Void (IP3)

IP-2302, EOF Technical Advisor & Information Liaison, Rev 10 (IP3)

IP-2310, EOF Onsite Radiological Communicator, Rev 4 (IP3)

Attachment

Attachment (contd) 4

IP-2400, Emergency Activation of the Alternate Emergency Operations Facility, Void

(IP3)

IP-2500, Security Emergency Activation Responsibilities, Rev 12 (IP3)

IP-2600, Emergency Termination & Transition to Recovery, Rev 4, Void (IP3)

IP-2601, Recovery Manager, Rev 1, Void (IP3)

IP-2602, Development of Recovery Plan, Rev 1, Void (IP3)

IP-2603, Recovery Support Group Manager, Rev 1

10CFR50.54(q) review for IPEC Emergency Plan

10CFR50.54(q) review for IP-EP-410

EP-AD-02, Emergency Planning Controlled Documents, Rev 3

EP-AD-03, Emergency Response Organization Training Program, Rev 1

Emergency Response Training Program Curriculum, Rev 16

TNG-AD-18, Emergency Response Training Program, Rev 8

QA-AD-3, IP3 Audit Program, Rev 5

Section 2OS1, Access Control to Radiologically Significant Areas

- SAO-302, Rev. 18, Radiation work permits (RWP) program

- HP-SQ-3.002, Rev. 16, Equipment and materials release requirements

- RW-SQ-4.109, Rev. 10, Radioactive material storage

- RWP 032009, Rev. 00, Assessments in RCA

- RWP 032028, Rev. 00, Non-outage vapor containment-all groups

- Radiation Protection performance goals for 2003

- Unit 2 housekeeping and area decon plan, February 25, 2003

- Quality assurance assessment report no. 02-AR-33-RP, November 11 - 15, 2002

- Continuing training - 2003, Session 1, Radiation Protection Alignment Session

Section 2OS2, ALARA Planning and Controls

- SAO-303, Rev. 11, ALARA program

- SAO-305, Rev. 10, Station ALARA committee

- IP1 and 2 Daily ALARA information for week of 02-16-2003

- IP1 and 2 Weekly exposure trend for 2003

- Pre-job, In-progress, and Post-job ALARA Reviews No.02-013 (RWP 025226) for

Outage valve work for 2R15

- Post-job review (ALARA review 02-013) for outage radioactive waste support

(RWP 025206) for 2R15

- Indian Point Energy Center/Radiation protection/2R15 outage ALARA review

- Indian Point Energy Center/Radiation protection/Strategic plan for exposure

reduction, 2003 - 2008

- IPEC ALARA committee meeting presentation handout for January 28, 2003

Attachment

Attachment (contd) 5

Section 2OS3, Radiation Monitoring Instrumentation and Protective Equipment

- Entergy South automated contamination monitor configuration, December 3,

2002

Section 2PS2, Radioactive Material Processing and Transportation

- RW-SQ-4.303, Rev. 14, Shipping cask handling procedure

- Procedures, license, and safety analysis report for the CNS 8-120B Type B

radioactive waste shipping cask, USA/9168/B(U)

Condition Reports Generated During this Inspection

IP3-2003-00480 Addresses minor issues associated with the development of the new plan.

Items include the handling of the lead accountability officer function,

description of the Safety Team Lead position, inclusion of core exit

thermal couples as instrumentation used, specifying a two hour joint news

center activation goal, distribution and updating of EALs to State and

County locations, clarification of drill applicability for the two units, and

removal of extraneous information from Table B-1.

IP3-2003-00493 Addresses review of Table B-1 staffing for a dual unit site with regards to

Technical Specification staffing requirements.

IP3-2003-00457 Addresses need to update emergency plan regarding KI when decision is

finalized by the State.

IP2-2003-01515 Scaffolding in the pipe penetration area near the containment pressure

transmitters not meeting station expectations.

IP2-2003-01520 Discrepancy between drawing and field conditions for 21 containment

spray pump discharge header drain

IP2-2002-09231 Pre-fire plan sketch for Fire Zone 90A in error

IP2-2003-00567 Fire Zone 6A discrepancies noted

IP2-2003-01673 Failure to incorporate a drawing revision to a non-operations critical

drawing

IP2 2003-01409 Unavailability time incorrect for the 22 CCW pump maintenance rule

IP2 2003-01037 Valves labels in auxiliary feedwater room do not match the check off list

IP2 2003-01161 Valve labels in the emergency diesel generator room do not match the

check off list

Condition Reports

Attachment

Attachment (contd) 6

IP2-2002-09152, IP2-2002-09054, IP2-2002-06818, IP2-2002-04701, IP2-2001-08308,

IP2-2001-05461, IP2-2001-02536,

LIST OF BASELINE INSPECTIONS PERFORMED

71111.04 Equipment Alignment 1R04

71111.05 Fire Protection 1R05

71111.06 Flood Protection Measures 1R06

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

71111.17 Permanent Modifications 1R17

71111.19 Post Maintenance Testing 1R19

71111.22 Surveillance Testing 1R22

71111.23 Temporary Plant Modifications 1R23

71114.04 Emergency Action Level and Emergency Plan Changes 1EP4

71114.06 Emergency Planning Drills 1EP6

71121.01 Access Control to Radiologically Significant Areas 2OS1

71121.02 ALARA Planning and Controls 2OS2

71121.03 Radiation Monitoring Instrumentation and Protective Equipment 2OS3

71122.02 Radioactive Material Processing and Transportation 2PS2

71151 Performance Indicator Verification 4OA1

71152 Problem Identification and Resolution Sample 4OA2

71153 Event Followup 4OA3

LIST OF ACRONYMS USED

AFWP auxiliary feedwater pump

ALARA as low as reasonably achievable

AOI abnormal operating instruction

BATP boric acid transfer pump

CAP corrective action program

CCR central control room

CCW component cooling water

CFR Code of Federal Regulations

CNS chem nuclear systems

COC certificate of compliance

COL check off list

CR condition report

DBI design basis initiative

DCP design change package

EAL emergency action level

EDG emergency diesel generator

EOF emergency operations facility

Attachment

Attachment (contd) 7

EP emergency preparedness

ESFS Engineered Safeguards Features System

FIP fundamental improvement plan

HRA high radiation area

ICMs Interim Compensatory Measures

INPO Institute of Nuclear Power Operations

IP Indian Point

IP2 Indian Point Unit 2

IPEC Indian Point Energy Center

IPEEE individual plant examination for external events

ISI inservice inspection

JNC joint news center

kV kilo-volt

Kw kilo-watt

LER licensee event report

LTC load tap changer

MOP motor operated potentiometer

NCV non-cited violation

NEI Nuclear Energy Institute

NRC Nuclear Regulatory Commission

NRR Nuclear Reactor Regulation

ODCM offsite dose calculation manual

OSC operations support center

OS occupational safety

PI performance indicator

PM post maintenance

PS public radiation safety

PT penetrant testing

PWT post-work test

RCA radiologically controlled area

RCS reactor coolant system

RHR residual heat removal

RMS radiation monitoring system

RPM radiation protection manager

RPS reactor protection system

RSPS risk significant planning standard

RV reactor vessel

RWP radiation work permit

SAO station administrative order

SAT station auxiliary transformer

SDP significance determination process

SI safety injection

SOP system operating procedure

TA temporary alteration

TI temporary instruction

TSC technical support center

TS technical specifications

Attachment

Attachment (contd) 8

UFSAR Updated Final Safety Analysis Report

V volt

WCCPPS weld channel and containment penetration pressurization system

WO work order

Attachment

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