ML082690653

IR 05000286-08-010, 05000247-08-012, on 07/28/2008 - 08/14/2008, Indian Point Nuclear Generating Units 2 and 3, Followup of Events and Notices of Enforcement Discretion and Other Activities

ML082690653
Person / Time
Site:	Indian Point
Issue date:	09/25/2008
From:	Doerflein L Engineering Region 1 Branch 2
To:	Joseph E Pollock Entergy Nuclear Operations
References
IR-08-010, IR-08-012
Download: ML082690653 (26)

See also: IR 05000247/2008012

Text

September 25, 2008

Mr. Joseph E. Pollock

Site Vice President

Entergy Nuclear Operations, Inc.

Indian Point Energy Center

450 Broadway, GSB

P.O. Box 249

Buchanan, NY 10511-0249

SUBJECT: INDIAN POINT ENERGY CENTER - NRC EVALUATION OF CHANGES,

TESTS, OR EXPERIMENTS AND PERMANENT PLANT MODIFICATIONS

TEAM INSPECTION REPORT - UNIT 2; AND OPEN ITEM CLOSEOUT - UNIT 3

COMBINED INSPECTION REPORT 05000247/2008012 AND

05000286/2008010

Dear Mr. Pollock:

On August 14, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection

at Indian Point Energy Center (IPEC). The enclosed inspection report documents the inspection

results, which were discussed on August 14, 2008, with Mr. T. Orlando, Director of Engineering,

and other members of your staff.

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

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

The inspection involved field walkdowns; examination of selected procedures, calculations and

records; observation of activities; and interviews with station personnel.

This report documents one NRC identified finding which was of very low safety significance

(Green). The finding was determined to involve a violation of NRC requirements. However,

because of the very low safety significance of the violation, and because it was entered into

your corrective action program, the NRC is treating it as a non-cited violation (NCV) consistent

with Section VI.A of the NRC Enforcement Policy. If you contest the NCV in this report, you

should provide a response within 30 days of the date of this inspection report, with the basis for

your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk,

Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region 1; the

Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C.

20555-0001; and the NRC Resident Inspectors at the IPEC.

J. Pollock 2

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

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

NRC Public Document Room or from the Publicly Available Records (PARS) component of the

NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at

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

Sincerely,

/RA/

Lawrence T. Doerflein, Chief

Engineering Branch 2

Division of Reactor Safety

Docket No: 50-247/286

License No: DPR-26, DPR-64

Enclosure: Combined Inspection Report 05000247/2008012 and 05000286/2008010

w/Attachment: Supplemental Information

cc w/encl:

Senior Vice President, Entergy Nuclear Operations

Vice President, Operations, Entergy Nuclear Operations

Vice President, Oversight, Entergy Nuclear Operations

Senior Manager, Nuclear Safety and Licensing, Entergy Nuclear Operations

Senior Vice President and COO, Entergy Nuclear Operations

Assistant General Counsel, Entergy Nuclear Operations

Manager, Licensing, Entergy Nuclear Operations

P. Tonko, President and CEO, New York State Energy Research and Development Authority

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

A. Donahue, Mayor, Village of Buchanan

J. G. Testa, Mayor, City of Peekskill

R. Albanese, Four County Coordinator

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

P. Eddy, NYS Department of Public Service

Assemblywoman Sandra Galef, NYS Assembly

T. Seckerson, County Clerk, Westchester County Board of Legislators

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

J. Pollock 3

M. Mariotte, Nuclear Information & Resources Service

F. Zalcman, Pace Law School, Energy Project

L. Puglisi, Supervisor, Town of Cortlandt

Congressman John Hall

Congresswoman Nita Lowey

Senator Hillary Rodham Clinton

Senator Charles Schumer

G. Shapiro, Senator Clinton's Staff

J. Riccio, Greenpeace

P. Musegaas, Riverkeeper, Inc.

M. Kaplowitz, Chairman of County Environment & Health Committee

A. Reynolds, Environmental Advocates

D. Katz, Executive Director, Citizens Awareness Network

K. Coplan, Pace Environmental Litigation Clinic

M. Jacobs, IPSEC

W. Little, Associate Attorney, NYSDEC

M. J. Greene, Clearwater, Inc.

R. Christman, Manager Training and Development

J. Spath, New York State Energy Research, SLO Designee

A. J. Kremer, New York Affordable Reliable Electricity Alliance (NY AREA)

J. Pollock 2

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

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

NRC Public Document Room or from the Publicly Available Records (PARS) component of the

NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at

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

Sincerely,

/RA/

Lawrence T. Doerflein, Chief

Engineering Branch 2

Division of Reactor Safety

Docket No: 50-247/286

License No: DPR-26, DPR-64

Enclosure: Combined Inspection Report 05000247/2008012 and 05000286/2008010

w/Attachment: Supplemental Information

Distribution w/encl: (via E-mail) M. Gray, DRP

S. Collins, RA B. Bickett, DRP

M. Dapas, DRA S. McCarver, DRP

M. Gamberoni, DRS G. Malone, DRP, IP2 SRI

D. Roberts, DRS C. Hott, DRP, IP2 RI

S. Williams, RI OEDO P. Cataldo, DRP, IP3 SRI

R. Nelson, NRR T. Koonce, DRP, IP3 RI

J. Boska, PM, NRR Region I Docket Room (with concurrences)

L. Doerflein, DRS ROPreports Resource

A. Ziedonis, DRS DRS File

SUNSI Review Complete: LTD (Reviewers Initials)

DOCUMENT NAME: G:\DRS\Engineering Branch 2\Ziedonis\Inspection Reports\IP2&3_combined_report--2008-

012_Mods_and_2008-010_URI_closeout.doc

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 ADAMS ACC#ML082690653

OFFICE RI/DRS RI/DRS RI/DRP RI/DRS

NAME AZiedonis/DS/LTD for WSchmidt/WCook for MGray/MG LDoerflein/LTD

DATE 09/24/08 09/24/08 09/25/08 09/25/08

OFFICIAL RECORD COPY

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No: 50-247, 50-286

License No: DPR-26, DPR-64

Report No: 05000247/2008012 and 05000286/2008010

Licensee: Entergy Nuclear Northeast

Facility: Indian Point Nuclear Generating Units 2 and 3

Location: 450 Broadway, GSB

Buchanan, NY 10511-0308

Dates: July 28, 2008 through August 14, 2008

Inspectors: A. Ziedonis, Reactor Inspector (Team Leader)

K. Mangan, Senior Reactor Inspector

S. Smith, Reactor Inspector

Approved by: Lawrence T. Doerflein, Chief

Engineering Branch 2

Division of Reactor Safety

Enclosure

SUMMARY OF FINDINGS

IR 05000286/2008-010, 05000247/2008-012; 07/28/2008 - 08/14/2008; Indian Point Nuclear

Generating Units 2 and 3; Followup of Events and Notices of Enforcement Discretion and Other

Activities.

The report documents a two week (on-site) team inspection covering the Evaluations of

Changes, Tests, or Experiments and Permanent Plant Modifications on Unit 2; open item

closure on Unit 3; and, Followup of Events and Notices of Enforcement Discretion inspections

on both units. The inspection was conducted by three region-based engineering inspectors.

One finding of very low risk significance (Green) was identified, and was considered to be a

non-cited violation. The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination

Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a

severity level after NRC management review. The NRCs program for overseeing the safe

operation of commercial nuclear power reactors is described in NUREG-1649, Reactor

Oversight Process, Revision 4, dated December 2006.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

• Green. The team identified a non-cited violation (NCV) of 10 CFR 50, Appendix B,

Criterion III, Design Control, because Entergy did not verify the adequacy of the

internal recirculation pump minimum flow rates. Specifically, Entergy did not verify

the adequacy of the pump minimum flow rates for sustained operation under low flow

rate conditions or for strong-pump to weak-pump interactions which could result in

dead-heading the weaker pump during parallel pump operation. Following

identification of the issue, Entergy revised the Emergency Operating Procedures

(EOP) to not start a second internal recirculation pump during conditions of high

head recirculation, submitted a licensee event report (LER) for each generating unit,

and entered the issue into the corrective action program.

The finding was determined to be more than minor because it is associated with the

design control attribute of the Mitigating Systems (MS) Cornerstone and affected the

cornerstone objective of ensuring the availability, reliability, and capability of systems

that respond to initiating events to prevent undesirable consequences. On Unit 2,

the team determined the finding was of very low safety significance because it was a

design or qualification deficiency confirmed not to result in loss of operability or

functionality. On Unit 3, the finding was determined to be of very low safety

significance based on a Significance Determination Process (SDP) Phase 3 risk

assessment. Also, the Unit 3 finding had a crosscutting aspect in the area of

Problem Identification and Resolution because Entergy did not implement operating

experience information through changes to station processes, procedures, and

equipment. (IMC 0305 aspect P.2 (b)) (Section 4OA5)

B. Licensee-Identified Violations

None.

ii

Enclosure

REPORT DETAILS

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications (IP

71111.17)

.1 Evaluations of Changes, Tests, or Experiments (24 samples)

a. Inspection Scope

The team reviewed one safety evaluation to determine whether the changes to the

facility or procedures, as described in the Updated Final Safety Analysis Report

(UFSAR), had been reviewed and documented in accordance with 10 CFR 50.59. In

addition, the team evaluated whether Entergy had been required to obtain NRC approval

prior to implementing the change. The team interviewed plant staff and reviewed

supporting information including calculations, analyses, design change documentation,

procedures, the UFSAR, technical specifications (TS), and plant drawings, to assess the

adequacy of the safety evaluation. The team compared the safety evaluation and

supporting documents to the guidance and methods provided in Nuclear Energy Institute

(NEI) 96-07, Guidelines for 10 CFR 50.59 Evaluations, as endorsed by NRC

Regulatory Guide 1.187, "Guidance for Implementation of 10 CFR 50.59, Changes,

Tests, and Experiments," to determine the adequacy of the safety evaluation.

The team also reviewed a sample of twenty-three 10 CFR 50.59 screenings and

applicability determinations for which Entergy had concluded that no safety evaluation

was required. These reviews were performed to assess whether Entergy's threshold for

performing safety evaluations was consistent with 10 CFR 50.59. The sample of issues

inspected that had been screened out by Entergy included procedure changes, design

changes, calculations, and set point changes.

The single safety evaluation reviewed was the only safety evaluation performed by

Entergy during the time period covered under this inspection (i.e., since the last team

inspection that evaluated changes, tests, or experiments). The screenings and

applicability determinations were selected based on the risk significance of the

associated structures, systems, and components (SSCs).

In addition, the team compared Entergy's administrative procedures, used to control the

screening, preparation, review, and approval of safety evaluations, to the guidance in

NEI 96-07 to determine whether those procedures adequately implemented the

requirements of 10 CFR 50.59. The safety evaluations, screenings, and applicability

determinations reviewed by the team are listed in the attachment.

b. Findings

No findings of significance were identified.

Enclosure

2

.2 Permanent Plant Modifications (8 samples)

.2.1 125 Volt Direct Current Circuit Breaker Replacements

a. Inspection Scope

The team reviewed a modification to replace the direct current (DC) HFB-model circuit

breakers in panel 23 due to breaker age concerns. The review was performed to

determine whether the design bases, licensing bases, and performance capability of the

DC electrical distribution system had been degraded by the modification. Additionally,

the 10 CFR 50.59 screen associated with this modification was reviewed as described in

section 1.1 of this report.

The team assessed selected design attributes to determine whether they were

consistent with the design and licensing bases. The attributes included component

safety classification, breaker trip coordination requirements, and seismic qualification of

the breaker and electrical panel. The team evaluated design assumptions in the

supporting evaluations and analyses to determine whether they were technically

appropriate and consistent with the Updated Final Safety Analysis Report (UFSAR).

The team reviewed selected evaluations, drawings, analysis, procedures, and the

UFSAR to determine whether they were properly updated with any revised design

information. The team evaluated the post-modification tests to determine whether the

breaker would function in accordance with design requirements. In addition, the team

interviewed the responsible design and system engineers to discuss the circuit breaker

replacements and design requirements. The documents reviewed are listed in the

attachment.

b. Findings

No findings of significance were identified.

.2.2 Removal of Turbine Trip Protection for Uneven Expansion

a. Inspection Scope

The team reviewed a modification to remove the turbine trip feature protecting against

uneven expansion of turbine rotational components with respect to the stationary

components of the system. The review was performed to determine whether the design

bases, licensing bases, and performance capability of the steam system or reactor

protection system had been degraded by the modification. Additionally, the 10 CFR

50.59 screen associated with this modification was reviewed as described in section 1.1

of this report.

The team assessed selected design attributes to determine whether they were

consistent with the design and licensing bases. These attributes included component

safety classification, adequacy of operator indication for protection of the turbine, and the

establishment of appropriate procedure guidance to manually trip the turbine in the event

of uneven turbine expansion. The team evaluated design assumptions in the supporting

evaluations and analyses to determine whether they were technically appropriate and

consistent with the UFSAR. The team reviewed selected evaluations, drawings,

Enclosure

3

analyses, procedures, and the UFSAR to determine whether they were properly updated

with any revised design information. The team evaluated the post-modification test to

verify that the trip function had been properly isolated. In addition, the team interviewed

the responsible design and system engineers to discuss the modification and the design

requirements. The documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

.2.3 Removal of Turbine Trip Protective Features

a. Inspection Scope

The team reviewed a modification to the main generator stator water cooling system.

The modification removed single point vulnerabilities that could lead to an inadvertent

main turbine trip, including main generator rectifier cooling flow and stator water cooling

inlet flow. The review was performed to determine whether the design bases, licensing

bases, and performance capability of the steam system or reactor protection system had

been degraded by the modification. Additionally, the 10 CFR 50.59 screen associated

with this modification was reviewed as described in section 1.1 of this report.

The team assessed selected attributes of the modification process to determine whether

they were consistent with the design and licensing bases. These attributes included

component safety classification, adequacy of operator indication for protection of the

turbine, and the establishment of appropriate procedure guidance to manually trip the

turbine based on alarms and other indications. Design assumptions were reviewed to

evaluate whether they were technically appropriate and consistent with the UFSAR. The

team reviewed selected calculations, drawings, analysis, procedures, and the UFSAR to

determine whether they were properly updated with revised design information and

operating guidance. The team evaluated the post-modification tests to verify that the

safety related trip functions associated with the turbine were not degraded by the

modification. In addition, the team interviewed the responsible design and system

engineers to discuss the modification and the design requirements. The documents

reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

.2.4 Internal Recirculation Pump Level Transmitter Modification

a. Inspection Scope

The team reviewed a modification to level transmitter LT-938, which is used for

indication of internal recirculation pump suction level during inservice testing. The

modification was performed to support changes in testing requirements of the internal

recirculation pumps, due to changes in American Society of Mechanical Engineers

(ASME) code acceptance criteria, which will require a higher suction water level to

ensure adequate submergence during testing at higher flow rates. The review was

Enclosure

4

performed to determine whether the design bases, licensing bases, and performance

capability of the internal recirculation system had been degraded by the modification.

Additionally, the 10 CFR 50.59 screen associated with this modification was reviewed as

described in section 1.1 of this report.

The team assessed selected design attributes to determine whether they were

consistent with the design and licensing bases. These attributes included component

safety classification, instrument uncertainty, adequacy of level transmitter position, and

adequacy of the water level for pump testing. The team evaluated design assumptions

in the supporting evaluations and analyses to determine whether they were technically

appropriate and consistent with the UFSAR. The team reviewed selected evaluations,

drawings, analysis, procedures, and the UFSAR to determine whether they were

properly updated with any revised design information. The team evaluated the post-

modification test to determine whether the final installed set points were within the

acceptance band to verify that the level transmitter would function in accordance with

design assumptions. In addition, the team interviewed the responsible design and

system engineers to discuss the modification and the design requirements. The

documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

.2.5 Installation of 3/4-inch Vent Line in Safety Injection System Piping

a. Inspection Scope

The team reviewed a modification to install a vent line on a relative high point in the

safety injection discharge line to allow for venting gasses to ensure the safety injection

piping remains full of water. The review was performed to determine whether the design

bases, licensing bases, and performance capability of the safety injection system had

been degraded by the modification. Additionally, the 10 CFR 50.59 screen associated

with this modification was reviewed as described in section 1.1 of this report.

The team assessed selected design attributes to determine whether they were

consistent with the design and licensing bases. These attributes included component

safety classification, ASME piping requirements, and procedural guidance for venting

operations. The team evaluated design assumptions in the supporting evaluations and

analyses to determine whether they were technically appropriate and consistent with the

UFSAR. The team reviewed selected evaluations, drawings, analysis, procedures, and

the UFSAR to determine whether they were properly updated with any revised design

information. The team evaluated the post-modification test to determine whether the

new piping and valve would function in accordance with design requirements. In

addition, the team interviewed the responsible design and system engineers to discuss

the installation of the vent line as well as design requirements. Finally, the team walked

down the safety injection system vent line to detect any potentially abnormal installation

conditions. The documents reviewed are listed in the attachment.

Enclosure

5

b. Findings

No findings of significance were identified.

.2.6 Modification to Replace Hydraulic Snubbers

a. Inspection Scope

The team reviewed documents regarding the replacement of Bergen-Patterson snubbers

with Lisega snubbers of equivalent load rating and pin-to-pin dimension. The Bergen-

Patterson snubbers were replaced due to age degradation and obsolescence. The new

snubbers were selected based on equivalency of design. Additionally, the new snubbers

enhanced design qualities related to inspection and preventive maintenance

requirements. The review was performed to determine whether the design bases,

licensing bases, and performance capability of systems and components supported by

the snubbers had been degraded by the modification. Additionally, the 10 CFR 50.59

screen associated with this modification was reviewed as described in section 1.1 of this

report.

The team assessed selected design attributes to determine whether they were

consistent with the design and licensing bases. These attributes included component

safety classification, load rating and load requirements, hydraulic fluid viscosity,

allowable displacement, and snubber inspection requirements. The team evaluated

design assumptions in the supporting evaluations and analyses to determine whether

they were technically appropriate and consistent with the UFSAR. The team reviewed

selected evaluations, drawings, analyses, procedures, and the UFSAR to determine

whether they were properly updated with any revised design information. In addition, the

team interviewed the responsible design and system engineers to discuss vendor

acceptance testing of the snubbers, as well as snubber installation and post-installation

inspection. Finally, the team walked down a sample of Lisega snubbers to detect any

potentially abnormal installation conditions. The documents reviewed are listed in the

attachment.

b. Findings

No findings of significance were identified.

.2.7 Main Boiler Feed Pump Temperature Control Valve Modifications

a. Inspection Scope

The team reviewed a modification to replace the temperature control valves (TCVs) on

the seal water injection system for the main boiler feed pump. The modification was

performed to increase the reliability of the automated temperature control feature, as

well as provide more appropriately sized valves for temperature control of the seal water

injection system. The review was performed to determine whether the design bases,

licensing bases, and performance capability of the safety injection system had been

degraded by the modification. Additionally, the 10 CFR 50.59 screen associated with

this modification was reviewed as described in section 1.1 of this report.

Enclosure

6

The team assessed selected design attributes to determine whether they were

consistent with the design and licensing bases. These attributes included component

safety classification, automated set points, manual valve control features, and the ability

to provide adequate seal water injection to ensure functionality of the main boiler feed

pumps. The team evaluated design assumptions in the supporting evaluations and

analyses to determine whether they were technically appropriate and consistent with the

UFSAR. The team reviewed selected evaluations, drawings, work orders, procedures,

and the UFSAR to determine whether they were properly updated with any revised

design information. The team evaluated the post-modification tests to determine

whether the new valves would function in accordance with design assumptions. In

addition, the team interviewed the responsible design and system engineers to discuss

the modification and the design requirements. Finally, the team walked down the new

TCVs to detect any potentially abnormal installation conditions. The documents

reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

.2.8 Modification to Install a Spacer Ring in Main Feedwater Valve

a. Inspection Scope

The team reviewed a modification to install a cage spacer in main feedwater flow control

valve (FCV) 427, to prevent the valve cage from shifting in position while in service. The

review was performed to determine whether the design bases, licensing bases, and

performance capability of the safety injection system had been degraded by the

modification. Additionally, the 10 CFR 50.59 screen associated with this modification

was reviewed as described in section 1.1 of this report.

The team assessed selected design inputs and attributes to determine whether they

were consistent with the design and licensing bases. These attributes included

component safety classification, effect on valve flow coefficient and stroke time, material

compatibility with feedwater chemistry, and evaluations for changes in piping stress.

The team evaluated design assumptions in the supporting evaluations and analyses to

determine whether they were technically appropriate and consistent with the UFSAR.

The team reviewed selected evaluations, drawings, analysis, procedures, and the

UFSAR to determine whether they were properly updated. The team evaluated the

post-modification tests to verify that the valves ability to stroke was not degraded by the

modification. In addition, the team interviewed the responsible design and system

engineers to discuss the modification and the design requirements. The team also

walked down the main feedwater flow control valves to detect possible abnormal

installation conditions. The documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

Enclosure

7

4. OTHER ACTIVITIES

4OA2 Identification and Resolution of Problems (IP 71152)

a. Inspection Scope

The team reviewed a sample of condition reports associated with 10 CFR 50.59 issues

and plant modification issues to determine whether Entergy was appropriately

identifying, characterizing, and correcting problems associated with these areas, and

whether the planned or completed corrective actions were appropriate. The condition

reports reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

4OA3 Follow-up of Events and Notices of Enforcement Discretion (IP 71153 - 2 samples)

.a Inspection Scope

.1 (Closed) LER 05000247/2007005, Technical Specification Prohibited Condition Due to

Exceeding the Allowed Completion Time for an Inoperable Recirculation Pump Caused

by a Potential Strong Pump-Weak Pump Interaction During a Small Break Loss of

Coolant Accident (SBLOCA)

On November 8, 2007, Unit 2 entered Technical Specification 3.5.2, Emergency Core

Cooling System, Condition A, for one or more Emergency Core Cooling (ECCS) trains

inoperable. A condition was identified, during an NRC Component Design Bases

Inspection, where a stronger internal recirculation pump could shut the discharge check

valve of the weaker internal recirculation pump, causing the weaker pump to deadhead.

This condition applied to certain accident scenarios with conditions of high pump head

and low flow, such as during a SBLOCA. Immediate actions were taken to declare one

train of the internal recirculation system inoperable, and revise Emergency Operating

Procedures (EOPs) to eliminate the requirement to start a second internal recirculation

pump. The team reviewed the LER, as well as the corrective actions to the EOPs to

verify that the changes were adequate. The team also reviewed additional procedures,

calculations, condition reports, corrective actions, and conducted interviews with

engineering staff to verify that the condition was adequately corrected. The team

determined that Entergys failure to evaluate the internal recirculation pumps for

adequate minimum flowrates was a finding of very low safety significance (Green)

involving a non-cited violation (NCV) of 10 CFR 50, Appendix B, Design Control (see

section 4OA5.1b below). This LER is closed.

.2 (Closed) LER 05000286/2007003, Technical Specification Prohibited Condition Due to

Exceeding the Allowed Completion Time for an Inoperable Recirculation Pump Caused

by a Potential Strong Pump-Weak Pump Interaction During a Small Break Loss of

Coolant Accident (SBLOCA)

On November 8, 2007, the Unit 3 internal recirculation pump no. 31 was declared

inoperable and Technical Specification 3.5.2, Emergency Core Cooling System,

Enclosure

8

Condition A, was entered for one or more Emergency Core Cooling (ECCS) trains

inoperable. A condition was identified, during an NRC Component Design Bases

Inspection, where a stronger internal recirculation pump could shut the discharge check

valve of the weaker internal recirculation pump, causing the weaker pump to deadhead.

This condition applied to certain accident scenarios with conditions of high pump head

and low flow, such as during a SBLOCA. Immediate actions were taken to declare one

train of the internal recirculation system inoperable, and revise Emergency Operating

Procedures (EOPs) to eliminate the requirement to start a second internal recirculation

pump. The team reviewed the LER, as well as the corrective actions to the EOPs to

verify that the changes were adequate. The team also reviewed additional procedures,

calculations, condition reports, corrective actions, and conducted interviews with

engineering staff to verify that the condition was adequately corrected. Also see section

4OA5.1a below for additional inspection activity related to this Unit 3 LER. The team

determined that Entergys failure to evaluate the internal recirculation pumps for

adequate minimum flowrates was a finding of very low safety significance (Green)

involving an NCV of 10 CFR 50, Appendix B, Design Control. (see section 40A5.1b

below) This LER is closed.

b. Findings

See section 4OA5.1b for the finding related to LERs 05000247/2007005 and

05000286/2007003.

4OA5 Other Activities

.1 (Closed) URI 05000286/2007006-02: Inadequate Design Control of Recirculation

Pumps

a. Inspection Scope

During the Unit 3 Component Design Bases Inspection (CDBI) performed in 2007, the

team identified an unresolved item (URI) concerning the adequacy of design control

associated with a modification that replaced both internal recirculation pumps (low

pressure recirculation (LPR) pumps 31 and 32, or 31 LPR pump and 32 LPR pump) in

March 2007. Specifically, Entergy did not assess two critical design parameters

associated with design basis requirements for the pumps: minimum flow requirements

for sustained pump operation under low flow conditions, which involved design flow rates

for small break loss-of-coolant accidents (SBLOCA) that were potentially below the

vendor recommended flow rates for sustained operation of the pumps; and strong-pump

to weak-pump interactions that could result in parallel pump dead-heading of the weaker

pump. With respect to conditions of parallel pump operation that result in a strong-pump

to weak-pump interaction, the weaker pump will become dead-headed without an

adequately sized minimum flow line. As a result of the NRC-identified issue, Entergy

determined that the weaker pump was only susceptible to dead-heading during SBLOCA

scenarios involving high head recirculation. Immediate corrective actions were taken by

Entergy to address this performance deficiency. URI 2007006-02 was opened to allow

an integrated NRC review of the LPR pumps prior operability with respect to pump

dead-heading, and also with respect to Entergys evaluation of the LPR pumps

sustained minimum flow requirements, which was still ongoing at the completion of the

CDBI inspection in December 2007.

Enclosure

9

During this inspection, the team completed the integrated review of both the sustained

minimum flow and the dead-heading issues. The team reviewed procedures, design

basis documents, calculations, condition reports, corrective actions, and conducted

interviews with engineering staff to verify measures were established to maintain design

basis requirements with respect to:

• the sustained minimum flow issue. The team reviewed recirculation system

hydraulic models performed by Entergy for SBLOCA scenarios to determine the

expected minimum core flows and individual pump flows. The team also

reviewed evaluations performed by the pump vendor, Flowserve, to evaluate the

sustained minimum flow requirements of the new internal recirculation pumps

during SBLOCA scenarios. Based on review of Entergys analyses and

Flowserves evaluations, the team was able to verify that individual pump flows

during SBLOCA scenarios would be sufficient to meet the sustained minimum

flow requirements for the pumps to operate successfully. The team noted the

analysis for LPR pump sustained minimum flow was performed on both units.

• the LPR pump dead-heading issue. The team reviewed completed surveillance

test data and vendor pump curve data. See the discussion under Description in

section 4OA5.1.b.

Based on the teams review of the Entergy analysis of the sustained minimum flow issue

and the corrective actions taken to address the dead-heading issue, this unresolved item

is closed.

b. Findings

Introduction: The team identified a finding of very low safety significance (Green)

involving a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design

Control, at both Unit 2 and Unit 3, because Entergy did not verify the adequacy of the

internal recirculation pump minimum flow rates. Specifically, Entergy did not verify the

adequacy of the pump minimum flow rates for sustained operation under low flow rate

conditions or for strong-pump to weak-pump interactions.

Description: For both units, the internal recirculation portion of the low-head safety

injection system consists of two low pressure recirculation (LPR) pumps, located in

primary containment, that take suction from a containment sump and discharge into a

common header. Each LPR pump has a 3/4-inch minimum flow line upstream of the

pump discharge check valve, and the two pumps share a 2-inch minimum flow line on

the common discharge header. All three minimum flow lines return to the containment

sump. With respect to system operation, prior to December 2007, the EOPs directed

operators to sequentially start both recirculation pumps during the recirculation phase of

any loss-of-coolant accident (LOCA).

NRC Bulletin 88-04, "Safety-Related Pump Loss," documented industry operating

experience regarding design deficiencies involving a weaker pump (i.e., low discharge

head at a given flow rate) that could be dead-headed when operated in parallel with a

stronger pump (i.e., higher discharge head at the equivalent flow rate), under low flow

conditions, for system configurations where both pumps share a common minimum flow

line. Letter IP3-89-036, dated May 12, 1989, provided the licenseesBulletin 88-04

Enclosure

10

response to the NRC. The licensee stated that although the recirculation pumps shared

a common minimum flow line, the potential for a stronger pump to dead-head a weaker

pump did not exist. The basis, in part, was that having the individual pump minimum

flow lines upstream of the pump discharge check valve would ensure flow through the

pump even if the stronger pump would cause the discharge check valve on the weaker

pump to close. The licensee also credited the EOPs with preventing the weak pump

from becoming dead-headed, based on an assumption that by the time the EOPs

directed starting of the second pump, flow to the reactor core would be sufficient to allow

both pumps to operate at a point on their performance curves where there was adequate

flow for both pumps.

In December 2007, following NRC identification of potential parallel pump dead-heading

of the LPR pumps at Unit 3, Entergy took actions to prevent the parallel operation of the

internal LPR pumps. Subsequent action was taken by Entergy at Unit 2 upon

confirmation of a similar configuration. Entergy entered this issue into their corrective

action program as CR-IP2-2007-04558 and CR-IP3-2007-04212. As an immediate

corrective action, Entergy revised EOPs 2-ES-1.2 and 2-ES-1.3, Transfer to Cold Leg

Recirculation, and also 2-ES-1.4 and 3-ES-1.4, Transfer to Hot Leg Recirculation, so

that the second internal recirculation pump would not be started during conditions of high

head recirculation on either unit.

The team concluded that Entergy, as part of the Unit 3 modification in 2007 and the Unit

2 modification in 2000 which installed two new LPR pumps on each unit, had not

evaluated the design for strong-pump to weak-pump interaction. Regarding Unit 3, the

team determined, based on a review of vendor supplied pump performance curves and

pump surveillance data, that the 31 LPR pump was susceptible to dead-heading if both

the 31 and 32 LPR pumps were operated in parallel during certain SBLOCA scenarios

involving high head recirculation, as required by EOPs. The team's review of the new

recirculation pump performance curves identified that the 32 LPR pump had

approximately 10 pounds-per-square-inch (psi) greater discharge pressure, under low

flow conditions, than the 31 LPR pump. The team noted that the installed 3/4 inch

minimum flow valve was throttled to 1.5 turns open, resulting in an as-found 0.1 gallons-

per-minute (gpm) flow. This low flow rate would not have been sufficient to prevent

pump damage if the 31 LPR pump discharge check valve closed due to the higher

discharge pressure for the 32 LPR pump.

In addition, the previous engineering evaluation for potential strong-pump to weak-pump

interaction of the recirculation pumps appeared to be inconsistent with Entergys most

current SBLOCA accident analysis performed as a result of the NRC-identified issue,

and also inconsistent with the current throttled configuration of the 3/4 inch minimum

flow line.

Regarding Unit 2, the team determined that it was unlikely that the 21 and 22 LPR

pumps were susceptible to parallel pump dead-heading, based on vendor pump curves

and surveillance test data, which showed that the current pump discharge pressures

were nearly equivalent for low flow conditions.

As noted in section 40A5.1a, Entergy performed an analysis for both units which

determined the individual LPR pump flows during SBLOCA scenarios would be sufficient

to meet the sustained minimum flow requirements for the pumps.

Enclosure

11

Analysis: The team determined that Entergys failure to evaluate the LPR pumps for

suitability of application to the internal recirculation system configuration at Unit 2 and

Unit 3 constituted a performance deficiency and a finding. Absent the 2007 NRC CDBI

identification of the issue at Unit 3, the similar issue at Unit 2 would likely have remained

undiscovered. The finding is greater than minor because it is associated with the design

control attribute of the Mitigating Systems (MS) Cornerstone and affected the

cornerstone objective of ensuring the availability, reliability, and capability of systems

that respond to initiating events to prevent undesirable consequences (i.e., core

damage).

Unit 3: Using Phases 1 and 3 of the NRCs Significance Determination Process, the

team determined the significance of the 31 LPR pump susceptibility to parallel pump

dead-heading, between March 2007 and December 2007. The team evaluated this

finding using NRC Inspection Manual Chapter (IMC) 0609.04, Phase 1 - Initial

Screening and Characterization of Findings. Using the Table 4a characterization

worksheet for the MS Cornerstone, the finding was determined to represent an actual

loss of a safety function for a single LPR train for greater than the Technical

Specification allowed outage time because of the differences in pump performance,

during certain SBLOCA scenarios that required high pressure recirculation (HPR).

Accordingly, this issue required evaluation under Appendix A to IMC 0609.

A Region I Senior Reactor Analyst (SRA) completed a Phase 3 risk assessment

determining that this issue was of very low safety significance (Green). The Phase 3

assessment was conducted because the issue was not suitable to a Phase 2 analysis.

The 31 LPR pump was assumed to fail internally, due to insufficient minimum pump flow

(pump damage), if the 32 LPR pump also was started in SBLOCA initiating events when

entering high pressure recirculation. The operation of the 31 LPR pump would not have

been affected if the 32 LPR pump failed to start independently or because it did not have

electrical power. The SRA used the IP3 Standardized Plant Analysis Review (SPAR)

model version 3.45 to complete an internal events review. As a bounding case, the SRA

assumed that the 31 internal LPR pump would fail to run in all SBLOCA initiating events.

The SRA then reviewed the increase in core damage probability for sequences where

HPR was assumed to fail. The dominate core damage sequence was a SBLOCA with:

success of AFW and high pressure injection, failure to cooldown, and subsequent failure

of HPR. The estimated increase in core damage probability, given the nine month

exposure period (March to December 2007), was very small: four-orders of magnitude

below the 1E-6 per year Green-White risk significance threshold (E-10 per year).

The cause of this finding had a cross-cutting aspect in the area of Problem Identification

and Resolution because Entergy did not implement operating experience information

through changes to station processes, procedures, and equipment (P.2.(b)).

Specifically, during the recent modification to the internal recirculation pumps, Entergy

did not sufficiently review their original response to NRC Bulletin 88-04 regarding the

potential dead-heading of safety related pumps. Additionally, previous Licensee Event

Reports (LERs) from other stations document that the same strong-pump to weak-pump

interaction has occurred at other power reactor plants within the industry.

Unit 2: The team determined that both LPR pumps (21 and 22) were not likely

susceptible to parallel pump dead-heading during certain SBLOCA scenarios, based on

vendor pump curves and current surveillance test data, and therefore would have

Enclosure

12

delivered adequate coolant flow to the reactor core as required by Emergency Operating

Procedures. The team evaluated this finding using NRC Inspection Manual Chapter

(IMC) 0609.04, Phase 1 - Initial Screening and Characterization of Findings. Using the

Table 4a characterization worksheet for the MS Cornerstone, the finding was determined

to be of very low safety significance (Green) because it was a design or qualification

deficiency confirmed not to result in loss of operability or functionality.

This deficiency was not indicative of current performance because the modification on

Unit 2 was performed in May of 2000. Therefore, there was no cross-cutting aspect

associated with this finding.

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

part, that measures be established for verifying or checking the adequacy of design such

as by the performance of design reviews, by the use of alternate or simplified

calculational methods, or by the performance of a suitable testing program. Contrary to

the above, Entergy replaced the internal recirculation pumps during modifications on

Unit 3 in March of 2007 and on Unit 2 in May 2000, and did not verify the design

adequacy of the pump minimum flow rates for sustained operation under low flow rate

conditions or for strong-pump to weak pump interactions which could result in dead-

heading the weaker pump during parallel pump operation. This condition existed until

identified by the NRC in December of 2007, resulting in subsequent corrective actions by

Entergy to revise the EOPs, as described above. Because this finding was of very low

safety significance and was entered into the corrective action program as CR-IP2-2007-

4558, and as CR-IP3-2007-4212, this violation is being treated as an NCV, consistent

with section VI.A.1 of the NRC Enforcement Policy. (NCV 05000247/2008012-01, and

NCV 05000286/2008010-01, Inadequate Design Control of Internal Recirculation

Pumps)

.2 (Closed) URI 05000247/2007007-03: Use of Motor Control Center (MCC) Methodology

for Periodic Verification of the Design Basis Capability of Safety-Related Motor Operated

Valves (MOVs)

a. Inspection Scope

During a Component Design Bases Inspection (CDBI) performed in 2007, the team

identified an unresolved item (URI) concerning the adequacy of MCC testing

methodology for MOVs. Specifically, Entergy did not use the testing methodology

approved by the NRC as part of the Generic Letter (GL) 96-05 reviews, which required

direct measurements of stem thrust and torque to be recorded at-the-valve. The URI

was opened to determine if the results from the MCC testing methodology could

adequately show that the design basis of the MOVs was maintained. The team

interviewed the system engineer and found that following NRC-identification of the issue,

Entergy suspended the MCC testing program, and subsequently re-tested all valves that

had been previously tested using the MCC testing methodology. The re-test used the

GL 96-05 testing methodology, and the team verified that the MOVs had maintained

their design basis capability.

Additionally, the team reviewed the licensees commitments as described in their

response to GL 96-05 and determined that Entergy had committed to the at-the-valve

testing methodology. The team concluded that prior to implementing the MCC testing

Enclosure

13

methodology, Entergy was required to submit a change to the GL commitment. The

team found that because the testing methodology did not conform to all the requirements

outlined in the methodology basis documents, and the testing had not been previously

approved by NRC, a violation of NRC requirements had occurred. However, because

the retest determined that the valves had maintained their design basis capability, the

team concluded that the associated finding was of minor significance that was not

subject to enforcement action per section IV.B of the Enforcement Policy. This URI is

closed.

b. Findings

No findings of significance were identified.

4OA6 Meetings, including Exit

The team presented the inspection results to Mr. T. Orlando, Director of Engineering,

and other members of Entergy's staff at an exit meeting on August 14, 2008. The team

verified that this report does not contain proprietary information.

Enclosure

A-1

ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

H. Anderson Licensing Specialist

F. Bloise Senior Design Engineer

G. Dahl Licensing Specialist

J. Hill Design Engineering Supervisor, I&C

T. McCaffrey Design Engineering Manager

V. Myers Design Engineering Supervisor, Mechanical

T. Orlando Director of Engineering

A. Vitale General Manager of Plant Operations

R. Walpole Licensing Manager

A. Williams Managers of Operations

J. Bencivenga Senior Design Engineer

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Open and Closed

05000247/2008012-01 NCV Inadequate Design Control of Internal

Recirculation Pumps (Section 4OA5.1)05000286/2008010-01 NCV Inadequate Design Control of Internal

Recirculation Pumps (Section 4OA5.1)

Closed

05000247/2007005 LER Technical Specification Prohibited Condition

Due to Exceeding the Allowed Completion

Time for an Inoperable Recirculation Pump

Caused by a Potential Strong Pump-Weak

Pump Interaction During a Small Break

Loss of Coolant Accident (Sections 4OA3.1)

05000286/2007003 LER Technical Specification Prohibited Condition

Due to Exceeding the Allowed Completion

Time for an Inoperable Recirculation Pump

Caused by a Potential Strong Pump-Weak

Pump Interaction During a Small Break

Loss of Coolant Accident (Section 4OA3.2)

Attachment

A-2

05000247/2007007-03 URI Use of Motor Control Center Methodology

for Periodic Verification of the Design Basis

Capability of Safety-Related MOVs (Section

4OA5.2)05000286/2007006-02 URI Inadequate Design Control of Internal

Recirculation Pumps (Section 4OA5.1)

LIST OF DOCUMENTS REVIEWED

Section 1R017: Evaluations of Changes, Tests, or Experiments and Permanent

Plant Modifications

10 CFR 50.59 Evaluations

07-2002-01-Eval, 10 CFR 72.212 Report Appendix F: New Licensing Basis Document

for IPEC ISFSI, Rev. 1

10 CFR 50.59 Screened-out Evaluations

0-AOP-SEC-2, Aircraft Threat, Rev. 4

2-PT-M021A, Emergency Diesel Generator 21 Load Test, Rev. 17

2-PT-M108R04, RHR/SI System Venting, dated 4/19/08

2-PT-Q024B, 22 EDG Fuel Oil Transfer Pump, Rev. 10

2-PT-Q033A, 21 Charging Pump, Rev. 13

2-PT-R007AR20, Motor Driven AF Pump Full Flow, dated 1/22/08

2-SOP-27.3.1.1 21 Emergency Diesel Generator Manual Operation, Rev. 21

EC 5456, Revision to the 22 AFP Turbine Overspeed Set Point Lower Tolerance, Rev. 0

EOPs E-0 through ES-3.2, Westinghouse Owners Group Changes to Revision Number 2 of the

EOPs (All procedures are Rev. 0)

ER-04-2-072, Main Boiler Feed Pump Seal Injection System Upgrade, Rev. 0

ER-05-2-137, Increase Reliability of the Stator Water Cooling Generator, Rev. 0

ER-06-2-027, Increase Recirculation Pump flows to meet IST Code Requirements by 2008,

dated 4/22/08

ER-06-2-031, 118V AC/ 118V AC Electrical (Replacement of 2 Pole HFB Bkrs in IP2 125V DC

Power Panel 23), Rev. 0

ER-06-2-048, Installation of 3/4 Vent Valve Downstream of SI-MOV-888A/B, Rev. 0

ER-06-2-058, Hydraulic Snubber Replacements, Rev. 0

ER-06-2-115, Install Surge Suppressors on Relays to Defeat 21 and 22 MBFP, Rev. 0

ER-06-2-141, DC/ 125 DC System (Removing Delta Expansion Turbine Trip), Rev. 0

ER-07-2-047, FCV-427 Anti-Rotation Device, Rev. 0

IP2-03-24983, Power Uprate: Setpoint Changes, dated 1/3/07

IP-CALC-06-00218, AST Analysis for a Design-Basis Stem Generator Tube Rupture Analysis,

Rev. 0

IP-SMM-AD-102, IPEC Implementing Procedure Preparation, Review, and Approval -

Attachment 10.2: Core Operation Limits Report (COLR), Rev. 5

SCR-07-2-058, Set Point Change Number 07-2-058, Internal Recirculation Pump Level

Transmitter Modification, Rev. 0

SPDDF-PC-439AR01, ESFAS Actuation on High Differential Steam line Pressure, dated

11/27/06

Attachment

A-3

Modification Packages

ER-04-2-072, Main Boiler Feed Pump Seal Injection System Upgrade, Rev. 0

ER-05-2-137, Increase Reliability of the Stator Water Cooling Generator, Rev. 0

ER-06-2-048, 3/4-inch Vent Line Install, Rev. 0

ER-06-2-058, Hydraulic Snubber Replacements, Rev. 0

ER-06-2-031, Replacement of 2 Pole HFB Bkrs in IP2 125V DC Power Panel 23, Rev. 0

ER-06-2-141, Removing Delta Expansion Turbine Trip, Rev. 0

ER-07-2-047, FCV-427 Anti-Rotation Device, Rev. 0

SCR-07-2-058, Set Point Change Number 07-2-058, Internal Recirculation Pump Level

Transmitter Modification, Rev. 0

Calculations & Analysis

IP-CALC-07-00184, SIS Valve Operation Inside the Vapor Containment, Rev. 0

IP-CALC-06-00218, AST Analysis for a Design-Basis Steam Generator Tube Rupture

Accident, Rev. 0

FIX-00046, Calibration of Turbine Inlet Pressure and High Steam Flow (SF)/ Safety

Injection Components for Stretch Power Uprate, Rev. 03P

FIX-00129, Turbine Inlet Pressure Transmitter Static Head Sealing and Calibrations,

Rev. 5

GMS-00035, Stress Analysis of Line 60 Due to Addition of Vent Valve Downstream of

888A and 888B, Rev. 0

Drawings

A225105, Logic Diagram - Safeguards Actuation Signals, Rev. 10

A225106, Logic Diagram - Feedwater Isolation, Rev. 7

ISI-2735, In-Service Inspection Program - Safety Injection System, Rev. 1

220619, Instrument and Control Loop Diagram Safety Injection System Loop 938 and

939, Rev. 2

9321-F-2019-114, Flow Diagram - Boiler Feedwater, 12/16/87

Drawing Change Notice (DCN)

EC-7052, Model D-1008-160-2 Valve Assembly (FCV-427), 04/04/08

Surveillance and Modifications Acceptance Tests

2-PT-Q62, High Steam Flow and Turbine First Stage Pressure Bistables, Rev. 14

2-PC-R19, Turbine First Stage Pressure, Rev. 21

PC-R19, Turbine First Stage Pressure, Rev. 19

PT-Q62, High Steam Flow and Turbine First Stage Pressure Bistables, Rev. 13

Audits and Self-Assessments

QA-04-2008-IP-1, Engineering Design Control, Rev. 0

Procedures

0-CY-1640, Chemistry Shutdown Plan, Rev. 17

0-CY-1645, Chemistry Response to Plant Causalities, Rev. 5

0-CY-2350, Primary System Zinc Injection, Rev. 2

0-RES-401-GEN, Lisega Snubber Installation and Removal, Rev. 1

2-ARP-SEF, Turbine and GE Generator Start-up, Rev. 55

2-PI-V001A, Inaccessible Snubber Inspections, Rev. 15

2-PI-V001B, Accessible Snubber Inspections, Rev. 14

Attachment

A-4

2-PT-M108, RHR/SI System Venting, Rev. 4

2-PT-R002B, Recirculation Sump Level, Rev. 18.

2-PT-R016, Recirculation Pumps, Rev. 20

2-PT-Q033A, 21 Charging Pump, Rev. 13

2-PT-Q62, High Steam Flow and Turbine First State Pressure Bistables, Rev. 14

2-SOP-3.1, Charging Seal Water and Letdown Control, Rev. 61

2-SOP-3.5, Placing CVCS Demineralizers in or out of Service, Rev. 22

EN-DC-117, Post Modification Testing and Special Instructions, Rev. 1

EN-LI-100, Process Applicability Determination, Rev. 7

EN-LI-101, 10 CFR 50.59 Review Program, Rev. 4

PT-V11A-4, Recalibration of NIS and OT/OP Delta T Parameters Channel IV, Rev. 14

Work Orders

51229162

51326377

00144204

Work Requests

128436

128439

Vendor Manuals

IB 56-352-400, TURBO-GRAF - Turbine Supervisory Instruments Differential Expansion

IP 56-352-340A, TURBO-GRAF -Turbine Supervisory Instruments Casing Expansion /

Differential Expansion

Miscellaneous

05-0299-MD-00-RE, 50.59 Evaluation for IP3 Cycle 14 Core Reload Design, Rev. 1

ER 03-2-217, Setpoints, Rev. 0

Final Report, Control Room Envelope In-leakage Testing at Indian Point 2 Nuclear Generating

Station, dated 02/00

Indian Point Nuclear Generating Unit No. 2 - Issuance of Amendment RE: 3.36 percent Power

Uprate (TAC No. MC 1865), dated 10/27/04

Indian Point 2 Improved Technical Specifications

Indian Point 2 Improved Technical Specifications

IPEC Top 10 Technical Issue: IPEC Power Supply PMs, Rev. 2

IP2-FW/SGL DBD, Feedwater System / Steam Generator Control System Design Basis

Document, Rev. 1

Letter from Consolidated Edison Company to NRC, NEI Pilot Program for use of NURGEG-

1465, dated 04/13/00

Letter from NRR to Entergy, Indian Point Nuclear Generating Unit No. 2 - Relief

Request P-2 on Testing of Recirculation Pumps, dated 04/01/08

Lisega: Shock Absorbers Rigid Struts 93, April 1996 Edition

Letter, Lake Engineering Co. to Entergy, Seal Life Evaluation of Bergen-Paterson

Snubbers Entergy Nuclear Contract No. 4500543558 - Change 1 Lake Engineering

Company Project No. 948, dated 12/28/05

Letter, USNRC to Consolidated Edison Company: Issuance of Amendment Number 173

for Indian Point Nuclear Generating Unit 2, dated 07/26/94

NF-IP-07-25, Indian Point Unit 2 Cycle Core 19 Loading Plan, 03/24/08

PFP-212, General Floor Plan - Primary Auxiliary Building, Rev. 7

Attachment

A-5

QA-04-2008-IP-1, Quality Assurance Audit Report: Engineering Design Control

Updated Final Safety Analysis Report: Indian Point Unit 2, Rev. 20

WCAP-16157-P, Indian Point Nuclear Generating Unit No. 2 Stretch Power Uprate NSSS and

BOP Licensing Report, Rev. 0

Westinghouse Certification of Conformance for Breaker RHFA3100Y, dated 03/28/08

Section 4OA2: Identification and Resolution of Problems

Condition Reports (* denotes NRC identified during this inspection)

IP2-2003-00231 IP2-2007-01208 IP2-2007-02208 IP2-2008-01056

IP2-2008-01414 IP2-2008-01581 IP2-2008-01822* IP2-2008-02011

IP2-2008-02509 IP2-2008-03778* IP2-2008-03801*

Section 4OA3: Event Followup

IP 2 LER 2007-005-00: Technical Specification Prohibited Condition due to Exceeding

the Allowed Completion Time for an Inoperable Recirculation Pump caused by a

Potential Strong Pump-Weak Pump Interaction During a Small Break LOCA,

01/07/08

IP 3 LER 2007-003-00: Technical Specification Prohibited Condition due to Exceeding

the Allowed Completion Time for an Inoperable Recirculation Pump caused by a

Potential Strong Pump-Weak Pump Interaction During a Small Break LOCA,

01/07/08

Section 4A05: Other Activities

10 CFR 50.59 Screened-out Evaluations

EC 5682, Revision of Procedures EOP ES-1.3 and ES-1.4, 02/12/08

Condition Reports

IP2-2007-04212 IP2-2007-04296 IP2-2007-04411 IP2-2007-04558

IP2-2007-04670 IP2-2007-04905 IP3-2007-04411

Procedures

2-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 1

2-ES-1.4, Transfer to Hot Leg Recirculation, Rev. 1

2-PT-R016, Recirculation Pumps, Rev. 20

3-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 1

3-ES-1.3, Transfer to Hot Leg Recirculation, Rev. 2

3PT-R013, Recirculation Pumps In-Service Test, Rev. 19

EN-DC-313, Procurement Engineering Process, Rev. 2

EN-DC-141, Design Inputs, 07/24/06

EN-DC-141, Design Inputs, 01/28/08

EN-MP-101, Materials, Purchasing, and Contracts Process, Rev. 2

EN-MP-121, Materials, Purchasing and Contracts Training, Qualification and

Certification, Rev. 1

QA-04-2008-IP-1, Quality Assurance Audit Report, Rev. 0

Miscellaneous

280-RLCA02848-02A, Unit 3 Internal Recirculation Pump Curves, 01/16/07

IP-CALC-04-00809, Attachment 10, Unit 2 Internal Recirculation Pump Curves, 01/11/00

Attachment

A-6

IP-RPT-04-00890, Technical Basis for Using MC2 Technology for Periodic Verification

Testing at Indian Point 2 and Indian Point 3, Rev. 02

IP-RPT-08-00009, Engineering Study for Pump Minimum Flow Evaluation - Safety

Injection Recirculation Pumps, 01/29/08

IPEC Licensed Operator Requalification Training Program: E-1 and FR-P Series EOPs,

06/25/08

Letter from Consolidated Edison Company to NRC, Completion of Licensing Action for

Generic Letter 96-05 Regarding Capability of Motor-Operated Valves, Indian

Point Nuclear Generating Unit No. 2 (TAC No. M97057), dated 03/05/01

NRC Bulletin 88-04: Potential Safety-Related Pump Loss, 05/05/88

NRC Inspection Report 05000286/2007006, Indian Point Unit 3 Component Design Bases

Inspection (CDBI), 02/01/08

NRC Regulatory Issue summary 2000-17, Managing Regulatory Commitments Made by Power

Reactor Licensees to the NRC Staff

PS98-002, Procurement Specification for Replacement of Two Containment

Recirculation Pumps, 04/08/99

SAO 270, Indian Point Station Procurement Program, 06/19/99

STR-27, Indian Point Energy Center MC2 Program Questions, Rev. 0

Attachment

A-7

LIST OF ACRONYMS

ASME American Society of Mechanical Engineers

CFR Code of Federal Regulations

DBA Design Basis Accident

DC Direct Current

ECCS Emergency Core Cooling System

EOP Emergency Operating Procedure

FCV Flow Control Valve

gpm Gallons per Minute

HPR High Pressure Recirculation

IMC Inspection Manual Chapter

IPEC Indian Point Energy Center

IR Inspection Report

LER Licensee Event Report

LOCA Loss-of-Coolant Accident

LPR Low Pressure Recirculation

MCC Motor Control Center

MOV Motor Operated Valve

MS Mitigating System

NCV Non-Cited Violation

NEI Nuclear Energy Institute

NRC Nuclear Regulatory Commission

PWR Pressurized Water Reactor

RCS Reactor Coolant System

SBLOCA Small Break Loss-of-Coolant Accident

SDP Significance Determination Process

SPAR Standardized Plant Analysis Review

SRA Senior Reactor Analyst

SSC Structures, Systems and Components

TS Technical Specification

UFSAR Updated Final Safety Analysis Report

URI Unresolved Item

Attachment