ML042240275
ML042240275 | |
Person / Time | |
---|---|
Site: | Indian Point ![]() |
Issue date: | 08/11/2004 |
From: | Brian Mcdermott Division Reactor Projects I |
To: | Dacimo F Entergy Nuclear Operations |
McDermott | |
References | |
IR-04-006 | |
Download: ML042240275 (41) | |
See also: IR 05000247/2004006
Text
August 11, 2004
Mr. Fred Dacimo
Site Vice President
Entergy Nuclear Operations, Inc.
Indian Point Energy Center
295 Broadway, Suite 1
P.O. Box 249
Buchanan, NY 10511-0249
SUBJECT: INDIAN POINT NUCLEAR GENERATING UNIT No. 2 - NRC INTEGRATED
INSPECTION REPORT 05000247/2004006
Dear Mr. Dacimo:
On June 30, 2004, the US Nuclear Regulatory Commission (NRC) completed an inspection at
the Indian Point Nuclear Generating Unit No. 2. The enclosed integrated inspection report
documents the inspection results, which were discussed on July 22, 2004, with Mr. C. Schwarz
and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations, and with the conditions of your license.
Within these areas, the inspection consisted of a selected examination of procedures and
representative records, observations of activities, and interviews with personnel.
Based on the results of this inspection, the inspectors identified five findings of very low safety
significance (Green). Four of the findings were determined to be violations of NRC
requirements. However, because of the very low safety significance and because the issues
have been entered into your corrective action program (CAP), the NRC is treating the findings as
non-cited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you
deny these NCVs, you should provide a response with the basis for your denial within 30 days of
the date of this letter, to the Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, D.C. 20555-001; with copies to the Regional Administrator, Region 1; the Director,
Office of Enforcement; and the NRC Resident Inspector at Indian Point 2.
Mr. Fred Dacimo 2
In accordance with 10 CFR 2.390 of the NRCs "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document Room
or from the Publicly Available Records (PARS) component of the NRCs document system
(ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-
rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Brian J. McDermott, Chief
Projects Branch 2
Division of Reactor Projects
Docket No.50-247
License No. DPR-26
Enclosure: Inspection Report 05000247/2004006
w/Attachment: Supplemental Information
cc w/encl:
G. J. Taylor, Chief Executive Officer, Entergy Operations, Inc.
M. R. Kansler, President - Entergy Nuclear Operations, Inc.
J. T. Herron, Senior Vice President and Chief Operating Officer
C. Schwarz, General Manager - Plant Operations
D. L. Pace, Vice President, Engineering
B. OGrady, Vice President, Operations Support
J. McCann, Director, Licensing
C. D. Faison, Manager, Licensing, Entergy Nuclear Operations, Inc.
P. Conroy, Manager, Licensing, Entergy Nuclear Operations, Inc.
M. Colomb, Director of Oversight, Entergy Nuclear Operations, Inc.
J. Comiotes, Director, Nuclear Safety Assurance
J. M. Fulton, Assistant General Counsel, Entergy Nuclear Operations, Inc.
P. R. Smith, President, New York State Energy, Research
and Development Authority
J. Spath, Program Director, New York State Energy Research and Development Authority
P. Eddy, Electric Division, New York State Department of Public Service
C. Donaldson, Esquire, Assistant Attorney General, New York Department of Law
T. Walsh, Secretary, NFSC, Entergy Nuclear Operations, Inc.
D. ONeill, Mayor, Village of Buchanan
J. G. Testa, Mayor, City of Peekskill
R. Albanese, Executive Chair, Four County Nuclear Safety Committee
S. Lousteau, Treasury Department, Entergy Services, Inc.
Chairman, Standing Committee on Energy, NYS Assembly
Chairman, Standing Committee on Environmental Conservation, NYS Assembly
Chairman, Committee on Corporations, Authorities, and Commissions
M. Slobodien, Director, Emergency Planning
Mr. Fred Dacimo 3
B. Brandenburg, Assistant General Counsel
P. Rubin, Manager of Planning, Scheduling & Outage Services
Assemblywoman Sandra Galef, NYS Assembly
County Clerk, Westchester County Legislature
A. Spano, Westchester County Executive
R. Bondi, Putnam County Executive
C. Vanderhoef, Rockland County Executive
E. A. Diana, Orange County Executive
T. Judson, Central NY Citizens Awareness Network
M. Elie, Citizens Awareness Network
D. Lochbaum, Nuclear Safety Engineer, Union of Concerned Scientists
Public Citizens Critical Mass Energy Project
M. Mariotte, Nuclear Information & Resources Service
F. Zalcman, Pace Law School, Energy Project
L. Puglisi, Supervisor, Town of Cortlandt
Congresswoman Sue W. Kelly
Congresswoman Nita Lowey
Senator Hillary Rodham Clinton
Senator Charles Schumer
J. Riccio, Greenpeace
A. Matthiessen, Executive Director, Riverkeeper, Inc.
M. Kapolwitz, Chairman of County Environment & Health Committee
A. Reynolds, Environmental Advocates
M. Jacobs, Director, Longview School
D. Katz, Executive Director, Citizens Awareness Network
P. Gunter, Nuclear Information & Resource Service
P. Leventhal, The Nuclear Control Institute
K. Coplan, Pace Environmental Litigation Clinic
R. Witherspoon, The Journal News
W. DiProfio, PWR SRC Consultant
D. C. Poole, PWR SRC Consultant
W. Russell, PWR SRC Consultant
W. Little, Associate Attorney, NYSDEC
Mr. Fred Dacimo 4
Distribution w/encl: (via E-mail)
S. Collins, RA
J. Wiggins, DRA
C. Miller, RI EDO Coordinator
R. Laufer, NRR
B. McDermott, DRP
W. Cook, DRP
C. Long, DRP
P. Habighorst, DRP, Senior Resident Inspector - Indian Point 2
M. Cox, DRP, Resident Inspector - Indian Point 2
R. Martin, DRP, Resident OA
Region I Docket Room (w/concurrences)
DOCUMENT NAME: C:\ORPCheckout\FileNET\ML042240275.wpd
After declaring this document An Official Agency Record it will be released to the Public.
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OFFICE RI/DRP RI/DRP RI/DRP
NAME PJHabighorst/WAC for WCook/WAC BJMcDermott/BJM
DATE 08/11/04 08/11/04 08/11/04
OFFICIAL RECORD COPY
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No. 50-247
License No. DPR-26
Report No. 05000247/2004006
Licensee: Entergy Nuclear Northeast
Facility: Indian Point Nuclear Generating Unit No. 2
Location: Buchanan, New York 10511
Dates: April 1, 2004 - June 30, 2004
Inspectors: P. Drysdale, Senior Resident Inspector
M. Cox, Resident Inspector
W. Cook, Senior Project Engineer
M. Snell, Reactor Inspector
J. Noggle, Senior Radiation Specialist
P. Habighorst, Senior Resident Inspector
S. Barr, Senior Reactor Engineer
J. Schoppy, Senior Reactor Engineer
Approved by: Brian J. McDermott, Chief
Projects Branch 2
Division of Reactor Projects
i Enclosure
CONTENTS
Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R04 Equipment Alignments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1R06 Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R07 Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R11 Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R13 Maintenance Risk Assessment and Emergent Work Activities . . . . . . . . . . . . . 12
1R14 Personnel Performance During Non-Routine Plant Evolutions and Events . . . 12
1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
1R19 Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1EP6 Emergency Plan Drill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
2OS3 Radiation Monitoring Instrumentation and Protective Equipment . . . . . . . . . . . 19
OTHER ACTIVITIES (OA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
4OA1 Performance Indicator (PI) Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA7 Licensee-Identified Violation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
ATTACHMENT: SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
LIST OF BASELINE INSPECTIONS PERFORMED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3
LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-8
ii Enclosure
SUMMARY OF FINDINGS
IR 05000247/2004006; 04/1/04 - 06/30/04; Indian Point Nuclear Generating Unit No. 2; Fire
Protection; Personnel Performance During Non-Routine Events; Maintenance Effectiveness;
and Problem Identification and Resolution.
The report covers a three month period of inspection by resident and region-based inspectors.
Four Green non-cited violations (NCVs) and one Green finding were identified. The
significance of most findings is indicated by their color (Green, White, Yellow, Red) using
Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings
for which the SDP does not apply may be Green or be assigned a severity level after NRC
management review. The NRCs program for overseeing the safe operation of commercial
nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3,
dated July 2000.
A. NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, for Entergys failure to translate the
emergency core cooling system (ECCS) design basis into recirculation sump
modification instructions. Specifically, Entergy added penetration cover plates
and alignment collars around several small pipes that penetrated the sump deck
plating, and the annular gap between the collars and pipes exceeded the sump
screen size.
This finding is more than minor because it potentially affected the mitigating
systems cornerstone objective of ensuring the availability, reliability, and
capability of ECCS. This finding is considered to be of very low safety
significance, because ECCS remained operable and there was no loss of safety
function. (Section 1R07.1)
- Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for Entergys failure to promptly
identify and take actions to address conditions adverse to quality associated with
the ECCS recirculation sump. Specifically, Entergy did not identify debris in
containment and recirculation sump bypass pathways that had the potential to
adversely impact ECCS during containment recirculation.
This finding is more than minor because it potentially affected the mitigating
systems cornerstone objective of ensuring the availability, reliability, and
capability of ECCS. This finding is considered to be of very low safety
significance, because ECCS remained operable and there was no loss of safety
function. (Section 1R07.2)
iii Enclosure
Summary of Findings (contd)
- Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for Entergys failure to promptly
identify and take actions to address a condition adverse to quality concerning
emergency diesel generator (EDG) heat exchanger (HX) fouling.
This finding was more than minor because it potentially affected the mitigating
systems cornerstone objective of ensuring the availability and reliability of the
EDG HXs to perform their intended safety function. This finding was associated
with the equipment performance attribute of the mitigating systems cornerstone.
However, this finding was determined to have very low safety significance
because the EDG HXs remained operable and capable of performing their
intended safety function. (Section 1R07.3)
- Green. The inspectors identified a finding due to ineffective and untimely
corrective actions associated with the 13.8 KV system during reduced voltage
conditions.
This finding was determined to be greater than minor since it impacts the
mitigating systems cornerstone objective of ensuring system reliability and
capability as associated with the procedure quality attribute of that cornerstone.
This finding was of very low safety significance since there was no loss of the
normal offsite power supplies and the 13.8 KV system was not providing power
to any safety-related loads during the degraded condition. (Section 1R15)
- Green. The inspectors identified a non-cited violation of Technical Specification
Surveillance Requirement SR 3.3.1.1. that requires, in part, that a channel check
be performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> on the feedwater flow instrumentation in the central
control room. This requirement had not been met since Entergy implemented
the Improved Technical Specifications in December of 2003.
This finding is greater than minor because it represents a condition similar to
example 1.c in Appendix E, IMC 0612, in that the Technical Specification
surveillance was not performed over an extended period (December 12, 2003
through June 8, 2004). The finding is of very low safety significance because the
feedwater flow instruments met the surveillance criteria when subsequently
performed, and did not render the mitigating equipment inoperable. (Section
1R22)
B. Licensee-Identified Violation
A violation of very low safety significance, which was identified by the licensee has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensees Corrective Action Program. This violation and
corrective actions is listed in Section 4OA7 of this report.
iv Enclosure
REPORT DETAILS
Summary of Plant Status
The Indian Point Nuclear Generating Unit No. 2 (IP2) reactor was at 100% power at the
beginning of the inspection period and remained at that level through the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity and Emergency
Planning
1R04 Equipment Alignments
a. Inspection Scope
Partial System Walkdowns (71111.04 - 3 samples)
The inspectors performed system walkdowns during periods of equipment unavailability
in order to verify that the alignment of the available train was proper to support the
associated safety functions and to ensure Entergy had identified equipment
discrepancies that could potentially impair the functional capability of the available train.
The inspectors reviewed applicable system drawings and check-off lists to verify proper
alignment and observed the physical condition of the equipment during the verification.
The following walkdowns were performed.
C Gas Turbine 3 (GT-3) while GT-1 was out of service for scheduled maintenance.
C Safety Injection Trains 21 & 23; safety injection pump 22 was out of service
during preventive maintenance on MOV-851A/B and -887A/B.
C Essential and non-essential service water headers after the quarterly header
swap.
Complete System Walkdown (71111.04S - 1 sample)
The inspectors performed an extensive walkdown of the 480 Volt system. The
inspectors walked down the entire system, with the exception of those components
located in the vapor containment, using revision 22 of procedure 2-COL 27.1.5, 480V
AC Distribution. The inspectors verified that components were in the proper position
per the checkoff list (COL) and verified that any position discrepancies were properly
documented. The inspectors also verified that the field configuration was consistent
with the current revision of the COL. The inspectors reviewed condition reports CR-IP2-
2004-1870, 1909 and 1911 which were written to address discrepancies between the
field configuration and current COL that were identified by the inspectors. The
inspectors verified that the associated corrective actions were appropriate. The
inspectors also evaluated the physical condition of the equipment during the walkdown.
Enclosure
2
b. Findings
No findings of significance were identified.
1R05 Fire Protection
a. Inspection Scope (71111.05Q - 7 samples)
The inspector toured areas that were identified as important to plant safety and risk
significant. The inspector consulted Section 4.0, Internal Fires Analysis, and the top
risk significant fire zones in Table 4.6-2, Summary of Core Damage Frequency
Contributions from Fire Zones, within the Indian Point 2 Individual Plant Examination for
External Events (IPEEE). The objective of this inspection was to determine if Entergy
had adequately controlled combustibles and ignition sources within the plant, effectively
maintained fire detection and suppression capability, and had adequately established
compensatory measures for degraded fire protection equipment. The inspector
evaluated conditions related to: 1) control of transient combustibles and ignition sources;
2) the material condition, operational status, and operational lineup of fire protection
systems, equipment and features; and 3) the fire barriers used to prevent fire damage or
fire propagation. The areas reviewed were:
C Zone 23, Auxiliary Boiler Feedwater Pump Room
C Zone 21, Main Turbine Hydrogen Seal Oil Unit
C Zones 55A, 56A, 57A, 58A, 21 & 22 Main Transformers, Unit Auxiliary
Transformer and Station Auxiliary Transformer
C Zone 140, Ventilation Equipment Room
C Zone 86A, 95 ft. Vapor Containment (VC) Refueling Floor
- Zones 72A, 75A, 76A, and 77A, 46 ft. Vapor Containment, Outer Annulus Areas
- Zones 80A, 81A, 82A, 83A, and 84A, 68 ft. Vapor containment, Containment fan
Cooler Areas
Reference material used by the inspector to determine the acceptability of the observed
condition of the fire areas included: the Fire Protection Implementation Plan; Pre-Fire
Plan; Station Administrative Order (SAO)-700, Fire Protection and Prevention Policy;
ENN-DC-161, Transient Combustible Program; SAO-703, Fire Protection Impairment
Criteria and Surveillance; and Calculation PGI-00433, Combustible Loading
Calculation.
b. Findings
No findings of significance were identified.
Enclosure
3
1R06 Flood Protection Measures
a. Inspection Scope (71111.06 - 1 sample)
The inspectors toured all elevations in the primary auxiliary building (PAB) that
contained equipment used to detect and mitigate an internal flood, and components
required for safe plant shutdown, with particular emphasis on the component cooling
water (CCW) pump and residual heat removal (RHR) pump areas. The areas selected
contained risk significant equipment based on the Individual Plant Examination for
External Events (IPEEE), Section 5, Internal Flooding. Internal flooding induced from
fire protection line breaks inside or just outside the PAB were predicted at mean
frequencies of 7.9E-5/year in the CCW pump area and 1.3E-4/year in the RHR pump
area. The inspectors verified the accuracy of the descriptive text in the IPEEE,
compared it with the actual conditions in the PAB, and assessed the physical condition
of the fire protection piping and components in those areas. Licensee-identified
equipment deficiencies awaiting corrective action were discussed with the fire protection
system engineer to confirm these conditions had been adequately evaluated.
b. Findings
No findings of significance were identified.
1R07 Heat Sink Performance
a. Inspection Scope (71111.07B - 1 sample)
Based on risk significance, resident inspector input, and the last biennial inspection, the
inspectors selected the RHR heat exchangers (HXs), the safety injection (SI) pump oil
coolers, and the EDG lube oil and jacket water (JW) HXs for this biennial review. The
EDG HXs transfer their heat loads directly to the service water (SW) system. The RHR
HXs and the SI pump coolers transfer their heat loads indirectly to the SW system
through an intermediate system (the component cooling water system). The SW
system was designed to supply cooling water from the Hudson River (the ultimate heat
sink) to various heat loads to ensure a continuous flow of cooling water to systems and
components necessary for plant safety during normal operation and under abnormal or
accident conditions.
The inspectors reviewed Entergys inspection, cleaning, chemical control, and
performance monitoring methods and frequency for the selected components to ensure
alignment with Entergys response to Generic Letter 89-13, Service Water System
Problems Affecting Safety-Related Equipment. The inspectors compared surveillance
test and inspection data to the established acceptance criteria to verify that the results
were acceptable and that operation was consistent with design. The inspectors walked
down the selected HXs, the sodium hypochlorite system, and the SW system to assess
the material condition of these systems and components. In addition, the inspectors
evaluated the containment fan cooler unit cooling coils and the containment sump for
Enclosure
4
indications of boric acid residue (indicative of potential reactor coolant system leakage)
during a containment walkdown to inspect the RHR HXs.
The inspectors also reviewed a sample of condition reports (CRs) related to the selected
HXs and the SW system to ensure that Entergy was appropriately identifying,
characterizing, and correcting problems related to these essential systems and
components. (The attachment to this report for Supplementary Information contains a
complete listing of documents reviewed.)
b. Findings
1. Recirculation Sump Deck Plate Design Deficiency
Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, for Entergys failure to translate the emergency
core cooling system (ECCS) design basis into recirculation sump modification
instructions. This finding is considered to be of very low safety significance because
there was no loss of safety function.
Description. The IP2 recirculation sump is designed with a course grating (1" x 4") and
a fine mesh screen (1/8" x1/8"). A solid deck plate at containment floor level is designed
as a barrier to preclude debris from entering the recirculation pump suction without
passing through the grating and the mesh screen. Entergy had previously modified the
sump to add penetration cover plates and alignment collars to cover existing gaps
around several small bore pipes that penetrate the sump deck plating.
During a containment walkdown on April 13, the inspectors noted several issues not
previously identified by Entergy. The inspectors identified loose sump deck plate
penetration cover plates and missing deck plate anchor bolts (see Section 1R07.2
below). Upon further review, the inspectors questioned the gap between the alignment
collars and the pipes penetrating the sump. During a subsequent sump inspection,
engineering determined that the annular gap between the alignment collars and the
pipes all exceeded 1/8". Entergy initiated condition reports to address these
deficiencies (CR-IP2-2004-01781, 2004-01820, 2004-01948, and 2004-01951). On
April 22, Entergy installed a temporary alteration (TA-04-2-078) to close the gap
between the collar and the piping and to hold the collars and cover plates in place to
preclude them from lifting or being dislodged during a LOCA blowdown.
Entergy evaluated the forces acting on the penetration cover plates and the solid deck
plate and determined that the plates would not have lifted or been dislodged during a
LOCA blowdown. Entergy also performed an operability evaluation for the pre-existing
annular gaps between the collars and the penetrating piping. Entergy determined that
these screen bypass flowpaths did not adversely affect the operability of the ECCS
components or the containment spray (CS) system. Entergys determination was based
primarily on: (1) calculation FMX-00142-00, Study the Effect of LOCA Generated
Debris on ECCS Performance; (2) the relatively low recirculation flow velocity (< 0.5
fps); (3) recirculation sump area layout (missile shield and other structures block larger
Enclosure
5
debris); (4) time to switch over to recirculation; (5) ECCS, fuel assembly, and CS system
flow path clearances; and (6) the relative size of the bypass paths compared to the
recirculation sump floor grating surface area (six square inches total compared to 48
square feet). The inspectors reviewed Entergys operability determination and the
applicable UFSAR sections to ensure that operability was justified and that potentially
affected ECCS components and CS remained available and capable of performing their
respective design functions.
Analysis. This issue was a performance deficiency because Entergy failed to
incorporate the recirculation design basis information in a modification which added
penetration cover plates and alignment collars around several small bore pipes that
penetrated the sump deck plating. Given the NRC correspondence and industry OE
relative to containment sump issues, the deficiency was reasonably within Entergys
ability to foresee and correct prior to April 2004.
The inspectors determined that this finding was more than minor because it potentially
affected the mitigating systems cornerstone objective of ensuring the availability,
reliability, and capability of ECCS sump recirculation to provide long-term heat removal.
This finding was associated with the design control and human performance attributes.
The inspectors determined that the finding was of very low safety significance (Green)
by the SDP Phase 1 screening worksheet for Mitigating Systems because the
containment sump screen qualification deficiency was evaluated in accordance with
NRC Generic Letter 91-18 (CR-IP2-2004-1948) and was confirmed not to result in a loss
of the long-term heat removal function.
Enforcement. 10 CFR 50, Appendix B, Criterion III, Design Control, requires that
measures shall be established to assure that applicable regulatory requirements and the
design basis are correctly translated into specifications, drawings, procedures, and
instructions. Contrary to this requirement, Entergy failed to correctly translate the ECCS
design basis (sump screen dimensions) into the recirculation sump modification
instructions, thus potentially impacting long-term heat removal function. However,
because of the very low safety significance and because the issue was entered into
Entergys Corrective Action Program (CAP) (CRs 2004-01781, 2004-01820, 2004-
01948, and 2004-01951), this finding is being treated as a non-cited violation, consistent
with Section VI.A of the Enforcement Policy, issued May 1, 2000 (65FR25368).
(NCV 50-247/04-06-01; Failure to implement appropriate design controls during
modifications to the recirculation sump)
2. Recirculation Sump Bypass Path and Debris
Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for Entergys failure to promptly identify
and take actions to address a condition adverse to quality concerning debris in
containment and a recirculation sump bypass path. This finding is considered to be of
very low safety significance because there was no loss of safety function.
Enclosure
6
Description. During a containment walkdown on April 13, the inspectors noted several
recirculation sump related issues not previously identified by Entergy. Debris inside
containment consisted of: a solid metal piece (2.5" in length, 3/8" diameter tapered to
1/8") located atop the sump deck plate cover (46 elevation); a putty knife (5" in length
with a wooden handle) located beneath RHR piping (68 elevation) directly above the
recirculation sump; and, an AA battery in the RHR HX room (68 elevation). Entergy
personnel also found a 5" pencil located on the floor outside the crane wall (46
elevation) and a small plastic bag (6" square) located on the floor (68 elevation). The
inspectors also identified a gap (approximately 1" x 3") between adjacent penetration
cover plates. During the walkdown, Entergy personnel removed the debris and
repositioned the loose penetration cover plate to close the gap. Entergy initiated CR-
IP2-2004-01781 to address these deficiencies.
Entergy performed an operability evaluation for the bypass path and the debris. Entergy
determined that this screen bypass flowpath and debris did not adversely affect the
operability of the ECCS components or the CS system. The inspectors reviewed
Entergys operability determination and the applicable UFSAR sections to ensure that
operability was justified and that potentially affected ECCS components and CS
remained available and capable of performing their respective design functions.
Entergy procedure SAO-213, Containment Entry, Egress and Inspection, Revision 4,
Attachment V, requires personnel to verify recirculation sump grating and floor in place
and pipe collars in place and to verify ALL debris removed. Entergy last implemented
Attachment V during their containment closeout in August 2003. The inspectors
considered this a missed opportunity as Entergy should have identified these
deficiencies prior to reactor startup in August 2003. Failure to do so represents a
weakness in Entergys attention-to-detail and problem identification during containment
closeout inspections. The August 2003 IP2 startup was also a missed opportunity to
apply IP3 operating experience related to containment sump deficiencies identified by
the NRC in April 2003. Although the inspectors could not determine with complete
certainty that the IP2 bypass path and containment debris existed at the time of
Entergys containment closeout inspection in August 2003, Entergy was not able to
identify any work activity performed in the recirculation sump area since that time.
Moreover, Entergy personnel offered that the misaligned deck cover plate and debris
may have existed since their Fall 2002 refueling outage due to the limited work in
containment during their August 2003 outage. In addition, the inspectors noted that
Entergy's monthly containment building inspections were missed opportunities to identify
these deficiencies.
Analysis. Entergys failure to identify degraded conditions with the potential to impact
operability of the recirculation sump is a performance deficiency. Given the NRC
correspondence and industry OE relative to containment sump issues, these
deficiencies were reasonably within Entergys ability to identify and correct prior to April
2004.
The inspectors determined that this finding was more than minor because it potentially
affected the mitigating systems cornerstone objective of ensuring the availability,
Enclosure
7
reliability, and capability of ECCS to respond to initiating events (LOCAs) to prevent
undesirable conditions. This finding was associated with the procedure quality and
human performance attributes as well as the cross-cutting issue of problem identification
and resolution. The inspectors determined that the finding was of very low safety
significance (Green) by the SDP Phase 1 screening worksheet for mitigating systems
because ECCS and CS remained operable and there was no loss of safety function.
Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in
part, that conditions adverse to quality are promptly identified and corrected. Contrary
to this requirement, Entergy failed to promptly identify and correct deficiencies
associated with the recirculation sump. Specifically, debris inside containment and a
sump screen bypass pathway existed from August 2003 until April 2004. However,
because of the very low safety significance and because the issue was entered into
Entergys CAP (CR-IP2-2004-01781), this finding is being treated as a non-cited
violation, consistent with Section VI.A of the Enforcement Policy, issued May 1, 2000
(65FR25368). (NCV 50-247/04-06-02; Failure to identify and correct deficiencies
associated with the recirculation sump)
3. Emergency Diesel Generator Heat Exchanger Fouling Evaluation
Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix
B, Criterion XVI, Corrective Action, for Entergys failure to promptly identify and take
actions to address a condition adverse to quality concerning emergency diesel
generator (EDG) heat exchanger (HX) fouling. This finding was considered to be of
very low safety significance because there was no loss of safety function.
Description. Based on a review of digital pictures from a February 2003 inspection, the
inspectors noted an excessive buildup of silt, grass, and other small river debris on the
No. 21 EDG lube oil and jacket water (JW) HXs (service water side, tube inlet, upper
return). System engineers had not identified the condition as a negative trend even
though the as-found grass/silt loading was significantly greater than previously found
during EDG HX inspections. The inspectors made this assessment based on the EDG
HX inspection reports available for review.
In addition, the inspectors noted that the following shortcomings contributed to Entergys
ineffective EDG HX trending and weak problem identification:
C Lack of detail in the documentation of the as-found condition relative to the
length, width, height, and depth of fouling buildup (SE-330, Attachment III, Visual
Inspection).
C No documentation of the in-service time between inspections (SE-330,
Attachment III, Trending).
C Previously completed inspection reports did not always contain as-found data
(usually in the form of digital pictures) for both EDG HXs (SE-330, Attachment
III, Visual Inspection).
Enclosure
8
C The Heat Exchanger Inspection Report, SE-330, did not provide guidance for the
use of a flashlight to evaluate the acceptability of tube fouling (Entergy personnel
used skill of the craft in using a flashlight to determine if tube blockage existed).
C The Heat Exchanger Inspection Report, SE-330, did not provide well-defined
acceptance criteria with respect to fouling buildup.
Engineering determined that the No. 21 EDG had remained operable based on
satisfactory EDG surveillance testing, EDG HX inspection results since February 2003,
and an ultrasonic flow measurement on the No. 23 EDG JW HX service water outlet on
April 21, 2004.
Analysis. The performance deficiency involved inadequate problem identification and
evaluation of a condition adverse to quality associated with increased fouling in the No.
21 EDG HXs. The inspectors determined the finding was more than minor because it
potentially affected the mitigating systems cornerstone objective of ensuring availability,
reliability, and capability of the EDGs to perform their safety function to provide
emergency power to mitigating systems. This finding was associated with the
equipment performance attribute of the mitigating systems cornerstone as well as the
cross-cutting issue of problem identification and resolution. However, this finding was
determined to have very low safety significance (Green) using the SDP Phase 1
screening worksheet because the EDG HXs remained operable and capable of
performing their intended safety function.
Enforcement. 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires, in
part, that conditions adverse to quality be promptly identified and corrected. Contrary to
this requirement, Entergy did not identify a condition adverse to quality associated with
EDG HX fouling and take appropriate actions to ensure that the cause was determined
and corrected. However, because the violation is of very low significance (Green) and
Entergy entered this deficiency into their corrective action system (CR IP2-2004-02241),
this finding is being treated as a non-cited violation, consistent with Section VI.A of the
Enforcement Policy, issued May 1, 2000 (65FR25368). (NCV 50-247/04-06-03; Failure
to identify a condition adverse to quality which could impact EDG reliability)
Enclosure
9
1R11 Licensed Operator Requalification Program
1. Resident Quarterly Review (71111.11Q - 1 sample)
a. Inspection Scope
The inspector observed the performance of Operating Team 2Z during licensed
operator annual simulator exam training. Specifically, the inspector observed one
simulator session which involved multiple anomalies and entry into the EOPs for
casualty response. The inspection was conducted to assess the adequacy of the
training, licensed operator performance, implementation of the emergency plan and the
adequacy of Entergys critique. The inspector evaluated the scenario to ensure that all
critical tasks were appropriately performed by the operating crew. The inspector also
verified that the training was conducted in accordance with procedures IP-SMM TQ-114,
Continuing Training and Requalification Examinations for Licensed Personnel, and
Training Administrative Directive #202, Conduct of Simulator Training.
b. Findings
No findings of significance were identified.
2. Operator Requalification Biennial Program Inspection (71111.11B - 1 sample)
a. Inspection Scope
An Operator Requalification Program inspection was conducted by two NRC region-
based inspectors from May 24 - 28, 2004. In addition, on July 7, 2004, an in-office
assessment of the 2004 annual operating exam results was performed using the
guidance of NRC Manual Chapter 0609, Appendix I, Operator Requalification Human
Performance Significance Determination Process (SDP).
The inspection activities were performed using NUREG-1021, Rev. 8, Operator
Licensing Examination Standards for Power Reactors, Inspection Procedure
Attachment 71111.11, Licensed Operator Requalification Program, and NRC Manual
Chapter 0609, Appendix I, Operator Requalification Human Performance Significance
Determination Process (SDP), as acceptance criteria, and 10 CFR 55.46 Simulator
Rule (sampling basis). The inspections were performed predominantly for IP2, although
some reviews did cover IP3 training activities.
The inspectors reviewed documentation of Unit 2 operating history since the last
requalification program inspection. The inspectors also discussed facility operating
events with the resident staff. Documents reviewed included NRC inspection reports
and licensee Condition Reports that involved human performance and Technical
Specification compliance issues.
The inspectors reviewed four comprehensive written exams from this biennial cycle that
were administered in 2004. The inspectors reviewed three sets of simulator scenarios
Enclosure
10
and 30 job performance measures (JPMs) also administered during this current exam
cycle to ensure the quality of these exams met or exceeded the criteria established in
the Examination Standards and 10 CFR 55.59.
The inspectors observed the administration of operating examinations to one crew (i.e.,
Operating Crew 2C). The inspectors observed three simulator scenarios for the
operating crew and one set of four in-plant and 13 control room JPMs administered to
individual crew members. As part of the examination observation, the inspectors
assessed the adequacy of licensee examination security measures.
The inspectors interviewed four evaluators, two training supervisors, three ROs, and five
SROs for feedback regarding the implementation of the licensed operator requalification
program. The inspectors also reviewed Training Review Group meeting minutes and
action items, QA audits, IPEC Focused Self-Assessment Reports on training, and recent
plant and industry events to ensure that the training staff modified the operator training
program, when appropriate, and responded to recommended changes.
Remedial training was assessed through the review of evaluation records for the past
two years, to ensure remediation plans were unique to the individual failures and both
timely and effective.
Conformance with operator license conditions was verified by reviewing the following
records:
- Attendance records for the last two year training cycle,
- Seven medical records to confirm all records were complete, that restrictions
noted by the doctor were reflected on the individuals license and that the exams
were given within 24 months,
- Proficiency watch-standing and reactivation records. Documentation of licensed
operator crew watch-standing was reviewed for the current and prior quarter to
verify currency and conformance with the requirements of 10 CFR 55.
The inspectors observed simulator performance during the conduct of the examinations
but did not conduct any further inspection of the IP2 simulator. The IP2 simulator fidelity
had been questioned as a result of operator performance following the August 3, 2003
loss of off-site power event (see NRC Inspection Report 50-247/2003-013), and Entergy
was still in the process of implementing corrective actions from that discovery. The
inspectors reviewed condition report CR-IP3-2004-01582, and interviewed the IP3
simulator staff, to ensure the issues identified with the IP2 simulator were being
appropriately addressed for the IP3 simulator.
On July 7, 2004, the inspectors conducted an in-office review of licensee requalification
exam results. These results included the annual operating test and the comprehensive
written exam for both IP2 and IP3. The inspection assessed whether pass rates were
consistent with the guidance of NRC Manual Chapter 0609, Appendix I, Operator
Requalification Human Performance Significance Determination Process (SDP). The
inspectors verified that:
Enclosure
11
- Crew failure rate on the dynamic simulator was less than 20%. (Failure rate was
0% for both units.)
- Individual failure rate on the dynamic simulator test was less than or equal to
20%. (Failure rate was 0% for both units.)
- Individual failure rate on the walk-through test (JPMs) was less than or equal to
20%. (Failure rate was 0% for both units.)
- Individual failure rate on the comprehensive written exam was less than or equal
to 20%. (Failure rate was 4.3% for IP2 and 0% for IP3.)
- More than 75% of the individuals passed all portions of the exam. (96% of the
individuals passed all portions of the exam for IP2 and 100% for IP3.)
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope (71111.12Q - 2 samples)
138 KV System
The inspector performed a review of maintenance issues associated with the 138KV
system dating back to 2002 by evaluating past condition reports and work orders
associated with the system. The inspector focused on work order IP2-02-63749
completed on May 25, 2004, which calibrated and replaced a synchronous check relay
for 138KV bus section 4-5 to evaluate work practices associated with the system. The
inspector reviewed the maintenance rule basis document to determine system
boundaries and verified that the system was being properly tracked in accordance with
the requirements of 10 CFR 50.65, Requirements of Monitoring the Effectiveness of
Maintenance. The inspector also reviewed the quarterly system health report for the 1st
quarter of 2004 and evaluated the system performance monitoring criteria for scope and
accuracy.
Enclosure
12
EQ Limit Switch ZC-PCV-1190-1 replacement
The inspector performed a review of maintenance issues associated with the
containment isolation valve (CIV) system dating back to 2002 by evaluating past CRs
and work orders associated with this system, and on valve performance test data. The
inspector focused on WO IP2-02-65939 completed on May 28, 2004, which replaced the
open limit switch ZC-PCV-1190-1 on relief valve PCV-1190, and WO IP2-04-18766,
which performed the post-maintenance stroke test of the valve. The inspector reviewed
the maintenance rule basis document to determine system boundaries and verified the
system was being properly tracked in accordance with the requirements of 10 CFR
50.65, Requirements for Monitoring the Effectiveness of Maintenance.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessment and Emergent Work Activities
a. Inspection Scope (71111.13 - 4 samples)
The inspector observed selected portions of emergent maintenance work activities to
assess Entergys risk management in accordance with 10 CFR 50.65(a)(4). The
inspector verified that Entergy took the necessary steps to plan and control emergent
work activities, to minimize the probability of initiating events, and to maintain the
functional capability of mitigating systems. The inspector observed and/or discussed
risk management with maintenance and operations personnel for the following activities.
C CR-IP2-2004-01894, Generex Regulator Trouble Alarm.
C Work Order (WO) IP2-04-19548, Replace GT-1 black start diesel jacket water
temperature switch.
C WO IP2-04-09050, 22 SG level indicator, current repeater card replacement.
C WO IP2-03-07175, 24 Battery Charger Ground Troubleshooting.
b. Findings
No findings of significance were identified.
1R14 Personnel Performance During Non-Routine Plant Evolutions and Events
a. Inspection Scope (71111.14 - 1 sample)
The inspectors reviewed operator response during a 13.8KV distribution system
automatic voltage reduction annual test on April 27, 2004. The inspectors reviewed
operator logs, system operating procedure (SOP) 27.1.3, Operation of 13.8KV
System, and discussed interactions between the on-shift crew and the grid operator to
determine if appropriate actions were taken based on the system conditions.
Enclosure
13
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope (71111.15 - 5 samples)
The inspectors reviewed the condition reports listed below and associated operability
evaluations to ensure operability was properly justified and that the component or
system remained available, without a significant degradation in performance or
unrecognized operability issue. As appropriate, the inspectors used Technical
Specifications (TS), Updated Final Safety Analysis Report (UFSAR), and design basis
documents. The inspector also conducted a physical walk down of the affected
equipment (when practicable), reviewed applicable drawings and operating procedures,
and discussed the operability evaluation with the responsible systems engineer.
Operability evaluations associated with these condition reports were also reviewed.
C CR-IP2-2004-01384, Charging pump reliefs back pressure compensation.
C CR-IP2-2004-01353, 13.8 KV breaker B2-2 after control power fuse
replacement.
C CR-IP2-2004-01716, SW pump/system operability post-LOCA during transition
to cold leg recirculation.
C CR-IP2-2004-02017, 13.8KV system during voltage reduction test.
C CR-IP2-2004-02648, GT-1 trip on compressor journal bearing high temperature
following monthly surveillance test.
b. Findings
. The 13.8 KV system is one of two off-site electrical circuits required by
Technical Specifications (TS).
Description. In May 2003, the NRC identified that Entergy had not adequately evaluated
the potential impact of a reduced voltage test on the operability of the 13.8 KV system
(CR IP2-2003-3470). The annual test, conducted by the transmission operator, reduces
the voltage of the TS required alternate power supply by eight percent. The inspectors
determined that Entergy's operability determination, completed after the test, was
inadequate based on the absence of an evaluation of in-plant accident electrical loads to
determine a minimum acceptable voltage required to be supplied by the 13.8 KV system
and the absence of communication protocols between Entergy and the transmission
operator for the control of degraded voltage testing. The NRC issued a Green Finding
(FIN 50-247/2003-007-01) based on the inadequate operability evaluation.
On April 27, 2004, the transmission operator again performed the annual voltage
reduction test on the 13.8 KV system. After discussion with the inspectors, the control
Enclosure
14
room operators made a late entry into TS LCO 3.8.1, condition A, for the 13.8 KV
system being out-of-service. The operators declared the 13.8 KV system inoperable
based upon the absence of procedural guidance on whether the system was operable at
the reduced voltage. TS LCO 3.8.1, condition A, was in effect for eight minutes and the
total duration of the test was 30 minutes. After further discussions with Entergy
personnel and a review of circumstances and documentation associated with the May
2003 finding, the inspectors determined that Entergy had not taken appropriate
corrective actions following the May 2003 event to provide the control room operators
with criteria for making an operability determination while the 13.8 KV system was under
test.
Analysis. The inspectors determined that the performance deficiency associated with
this event was Entergys failure to implement appropriate corrective actions, including an
evaluation of the minimum acceptable voltage requirement for the 13.8 KV off site
power source, to prevent a recurrence of the May 2003 event. Entergy had not
corrected their May 2003 operability evaluation and had not provided appropriate
guidance to plant operators in the event the 13.8 KV electrical power feed became
similarly degraded. Traditional enforcement does not apply since there were no actual
safety consequences or potential for impacting the NRCs regulatory function, and the
finding was not the result of any willful violation of NRC requirements or Entergys
procedures. This finding was determined to be greater than minor because it impacted
the mitigating systems cornerstone objective, and was associated with the cornerstones
procedure quality attribute.
TS bases state that the 13.8 kV system is a delayed access power source since
operator action is required to align the 13.8 KV system to supply the plant. The UFSAR,
Chapter 8, "Electrical Systems," states that the 13.8 KV system should be available in
sufficient time following a loss of onsite power, and the other offsite power circuits (138
KV), to ensure that fuel design limits and design conditions for the reactor coolant
system are not exceeded. After the 13.8 KV system operability questions were raised
by the inspector on April 27, 2004, Entergy determined that the minimum required
voltage to ensure reliable ECCS operation was 13.4 kV (<3 percent reduction). Based
upon this criteria, the inspectors determined that the licensee failed to ensure the
reliability and capability of mitigating systems supplied by the 13.8 KV system. This
finding relates to the cross-cutting issue of problem identification and resolution. The
inspectors conducted a Phase 1 SDP screening and determined that the failure to
implement appropriate and timely corrective actions was of a very low safety
significance since there was no loss of the normal offsite power supplies and the 13.8
KV system was not providing power to any safety-related loads during the degraded
condition. This issue has been placed in Entergys CAP as CR-IP2-2004-2766.
Enforcement. No violation of regulatory requirements occurred. The inspector
determined that the failure to perform timely corrective actions occurred on a non-safety
related system and therefore did not fall under the requirements of 10 CFR 50,
Appendix B. (FIN 50-247/04-06-04; Failure to implement adequate corrective
actions for low voltage conditions on the 13.8 KV system)
Enclosure
15
1R19 Post Maintenance Testing
a. Inspection Scope (71111.19 - 5 samples)
The inspector reviewed post-work test (PWT) procedures and associated testing
activities to assess whether: 1) the effect of testing in the plant had been adequately
addressed by control room personnel; 2) testing was adequate for the maintenance
work order (WO) performed; 3) acceptance criteria were clear and adequately
demonstrated operational readiness consistent with design and licensing documents; 4)
test instrumentation had current calibrations, range, and accuracy for the application;
and 5) test equipment was removed following testing.
The selected testing activities involved components that were risk significant as
identified in the IP2 Individual Plant Examination. The regulatory references for the
inspection included Technical Specification 6.8.1.a. and 10 CFR 50, Appendix B,
Criterion XIV, Inspection, Test, and Operating Status. The following testing activities
were evaluated:
C WO IP2-03-24066, PWT for pressure control valve PCV-1139 (22 ABFP Steam
Supply) following diagnostic testing.
C WO IP2-04-19810, PWT for 22 CCW Pump after motor replacement.
C WO IP2-04-19539, PWT for 21 SG Atmospheric Steam Dump (PCV-1134)
following actuator maintenance.
C WO IP2-03-28334 & 22618, PWT for 22 Charging Pump after internal valve
replacement.
- WO IP2-04-09383, PWT for GT-1 after flame detector failure.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope (71111.22 - 7 samples)
The inspector reviewed surveillance test procedures and observed testing activities to
assess whether: 1) the test preconditioned the component tested; 2) the effect of the
testing was adequately addressed in the control room; 3) the acceptance criteria
demonstrated operational readiness consistent with design calculations and licensing
documents; 4) the test equipment range and accuracy was adequate and the equipment
was properly calibrated; 5) the test was performed per the procedure; 6) test equipment
was removed following testing; and 7) test discrepancies were appropriately evaluated.
The surveillance tests observed were based upon risk significant components as
identified in the IP2 Individual Plant Examination. The regulatory requirements that
provided the acceptance criteria for this review were 10 CFR 50, Appendix B, Criterion
V, Instructions, Procedures, and Drawings, Criterion XIV, Inspection, Test, and
Enclosure
16
Operating Status, Criterion XI, Test Control, and Technical Specifications 6.8.1.a.
The following test activities were reviewed:
C PT-Q27A 21; Auxiliary Boiler Feedwater Pump Functional Test
C PT-Q51; Nuclear Power Range Analog Test
C PT-SA13, Cable Spreading Room Halon Functional Test
C PT-D001, Control Room Operations Surveillance Requirements
C PT-M48, 480 Volt Undervoltage Alarm Test
- PI-M-2, Containment Building Inspection
- PT-Q62, High Steam Flow / 1st Stage Pressure Bistable Setpoint Test
b. Findings
Introduction. A Green NCV was identified for Entergys failure to properly implement a
surveillance required by the Technical Specifications (TS). Entergy had not performed
channel checks on the feedwater flow instrumentation since implementing the Improved
Standard Technical Specifications (ITS) on December 12, 2003. This was determined
to be a violation of Technical Specification Surveillance Requirement SR 3.3.1.1, which
requires that a channel check be performed on the feedwater flow instrument every
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Description. On June 4, 2004, Entergy noted that one channel of feedwater flow to the
21 steam generator was reading 0.3 million pounds mass per hour less than the other
channel. The inspector discussed this condition with a licensed operator to determine if
this was less than the maximum deviation allowed for the instrument channel check.
The operator informed the inspector that no channel check was performed on the feed
flow instrumentation and that none was required. Upon further review, the inspector
found that SR 3.3.1.1 required that a channel check for feedwater flow was required to
be performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This requirement had not been met since Entergy
implemented ITS in December of 2003. Entergy documented this deficiency in CR-IP2-
2004-2656 and implemented actions to perform the appropriate surveillance on the
required periodicity.
Analysis. The inspectors determined that this was a performance deficiency since
Entergy failed to perform the required surveillance. Control room operators perform
surveillance procedure 2-PT-D001, Control Room Operations Surveillance
Requirements, every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, which captures the channel checks required by ITS in
the control room; however, the feedwater flow instruments were omitted from this
procedure. Traditional enforcement does not apply since there were no actual safety
consequences or potential for impacting the NRCs regulatory function, and the finding
was not the result of any willful violation of NRC requirements or Entergy procedures.
This finding was determined to be greater than minor because it represents the
conditions similar to those described by example 1.c in Appendix E of IMC 0612,
involving the failure to perform a TS surveillance test for an extended period of time.
The feedwater flow signal is used in conjunction with steam flow and steam generator
(SG) level to ensure protection is provided against a loss of heat sink, and actuates the
Enclosure
17
auxiliary feedwater (AFW) system prior to a low level that could uncover the SG tubes.
The channel check surveillance is a qualitative assessment performed by observation of
channel behavior during operation which includes a comparison of multiple channel
indications. This is used to help assure that the system will operate properly when
required to perform its safety function. The failure to perform the required surveillance
impacted the mitigating systems cornerstone objective, and was associated with the
cornerstones procedure quality attribute. Entergys failure to include this surveillance in
their test procedure prevented them from ensuring the reliability of a system that
responds to initiating events to prevent undesirable consequences. The inspectors
conducted a Phase 1 SDP screening and determined that the failure to perform the
required surveillance was of a very low safety significance since the feedwater flow
instruments met the surveillance criteria when subsequently performed, and did not
render the mitigating equipment inoperable.
Enforcement. ITS SR 3.3.1.1 requires, in part, that a channel check of feedwater flow
instrumentation be performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to this requirement Entergy
failed to perform this surveillance requirement from December 12, 2003 to June 8, 2004.
This was determined to be a violation of Entergys Technical Specifications. Because
this violation is of very low safety significance and has been entered in Entergys
corrective actions program (CR IP2-2004-2656), this violation is being treated as an
NCV consistent with Section VI.A of the NRC Enforcement Policy: (NCV 50-247/04-06-
05; Failure to implement a Technical Specification Surveillance Requirement).
1R23 Temporary Plant Modifications
a. Inspection Scope (71111.23 - 2 samples)
The inspector reviewed temporary alterations associated with the recirculation sump and
the containment sump that were initiated to prevent sump screen bypass flow via gaps
around piping and associated equipment penetrations in the deck plating directly above
the sumps. The inspector reviewed: 1) the individual temporary alteration control
packages to ensure these plant modifications were performed in accordance with ENN-
DC-136, Temporary Alterations, Revision 7, dated 3/29/04; and 2) to ensure
compliance with 10 CFR 50.59 screen-out evaluations associated with each of these
modifications. To verify compliance, the inspector also conducted a visual examination
of each of the temporary alterations in containment on June 19, 2004, in conjunction
with Entergys monthly containment entry and inspection at power conditions. The
inspector reviewed the following documents associated with temporary modifications of
the recirculation sump and the containment sump:
Recirculation Sump
C TA-04-2-078, Install clamps on pipe collars around recirculation pump 21 and 22
bypass lines, WO No. IP2-04-18017; installed April 22, 2004.
C TA-04-2-080, Install clamp on 2-inch pipe (line No. SI-601R-293) above the
collar at the recirculation sump, WO No. IP2-04-18146; installed April 28, 2004.
Enclosure
18
C TA-04-2-081, Install a temporary clamp on the identified pipe above the collar at
the recirculation sump, WO No. IP2-04-18178; installed April 28, 2004.
C TA-04-2-083, Install a clamp on No. 22 recirculation pump one-inch drain line
from seal leak-off and motor cooler to the recirculation sump above the collar,
WO No. IP2-04-18321; installed April 28, 2004.
Containment Sump
C TA-04-2-082-001, Reduce gap around components penetrating the containment
sump deck plate, WO No. IP2-04-18268, installed April 28, 2004.
The inspector also referenced station procedure ENN-LI-101, 10 CFR 50.59 Review
Process.
b. Findings
No findings of significance were identified.
1EP6 Emergency Plan Drill
a. Inspection Scope (71114.06 - 1 sample)
On May 12, 2004, the inspectors observed Entergys emergency response organization
during an announced emergency preparedness training drill initiated at IP3 and
extending to the entire site. The simulated emergency included the activation of the
Operations Support Center (OSC),Technical Support Center (TSC), Emergency
Operations Facility (EOF), and the Joint News Center (JNC) after an Alert (simulated)
was declared by the simulator control room operators.
The inspectors observed the conduct of the exercise in the TSC and the EOF. The
inspectors assessed licensed operator performance, Entergys adherence to Emergency
Plan Implementing Procedures, and their response to simulated degraded plant
conditions. The inspectors verified licensee performance in the classification,
notification, and protective action recommendations. In addition to the drill, the
inspectors observed Entergys controller critique and evaluated Entergys self-
identification of weaknesses and deficiencies. CR-IP2-2004-00599 concluded that three
of four performance indicator opportunities (classifications, notifications, and protective
action recommendations) were successful. The inspectors compared Entergys
identified findings against their observations.
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety (OS)
Enclosure
19
2OS3 Radiation Monitoring Instrumentation and Protective Equipment
a. Inspection Scope (71121.03 - 9 samples)
During May 10-14, 2004, the inspector conducted the following activities to evaluate the
operability and accuracy of radiation monitoring instrumentation, and the adequacy of
the respiratory protection program for issuing self-contained breathing apparatus
(SCBA) to emergency response personnel. Implementation of these programs was
reviewed against the criteria contained in 10 CFR 20, applicable industry standards, and
Entergys procedures. Nine inspection activity samples were selected consistent with
Sections 02.01 through 02.06 of Inspection Procedure 71121.03. The inspector also
reviewed the Condition Reports involving radiation protection relate matters initiated
between April and May 2004.
Plant walkdowns of accessible plant radiation monitors, review of the calibration
methods and review of the most recent calibration records were performed for the
following instruments:
- R-28, 29, 30, 31, main steam line radiation monitors
- R-41, 42, gaseous and particulate containment radiation monitors
- R-2,7, refueling floor area radiation monitors
- R-49, steam generator blow down radiation monitor
The inspector selected in-use portable radiation survey and continuous air monitor
instruments for operable condition, source response checks, and reviewed the most
recent calibration records for the following instruments:
- PRM-7 micro-R meter #315
C RO-2 ion chamber #05250
C RO-2A ion chamber #10193
C Teletector # 05177
C Gilian lapel air samplers # 05266 and 05269
C NMC continuous air monitor #05277
C RM-14 contamination monitor #05161
The inspector evaluated the adequacy of the respiratory protection program regarding
the maintenance and issuance of self-contained breathing apparatus (SCBAs) to
emergency response personnel. Training and qualification records were reviewed for
42 licensed operators from each of the six operating shifts, who would be required to
wear SCBAs in the event of an emergency. Emergency plan specified SCBA
equipment and air bottle inventory, for the IP2 control room and technical support
center, were verified. Selected SCBAs and air bottles were verified to be operable.
Maintenance records were also reviewed.
b. Findings
No findings of significance were identified.
Enclosure
20
4. OTHER ACTIVITIES (OA)
4OA1 Performance Indicator (PI) Verification
a. Inspection Scope (71151 - 5 samples)
The inspectors reviewed Entergys Performance Indicator (PI) data for five indicators to
verify whether the data was accurate and complete. The inspectors compared the PI
data reported by Entergy to information gathered from control room logs, condition
reports, and work orders for the four quarters of 2003 and the first quarter of 2004. In
addition, the inspectors compared the PI data against the guidance contained in NEI 99-
02, Revision 1.
Reactor Safety Cornerstone
C Unplanned Power Changes per 7,000 Critical Hours
C Safety System Unavailability - Auxiliary Feedwater
C Safety System Unavailability - Emergency AC Power
C Reactor Coolant System Activity
The inspector observed an RCS activity sample in progress and the subsequent
laboratory analysis on June 25, 2004, and compared the results and trend to the PI data
reported for the fourth quarter of 2004.
C Scrams with Loss of Normal Heat Sink
The inspector noted that the three unplanned scrams and loss of normal heat removal
events that occurred in 2003 (April 28, August 3, and August 14) were all attributed to
loss of offsite power events. However, consistent with Regulatory Issue Summary 2001-
25, which endorses NEI 99-02 guidance, and NRCs response in Frequently Asked
Questions 354, posted September 25, 2003, these three loss of normal heat removal
events are not counted under this PI.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
1. Baseline Procedure Problem Identification and Resolution Review (71152)
As required by Inspection Procedure 71152, "Identification and Resolution of Problems,
and in order to help identify repetitive equipment failures or specific human performance
issues for follow-up, the inspectors screened each item entered into Entergys
Corrective action program. This review was accomplished by reviewing hard copies of
each condition report.
Enclosure
21
2. Semi-annual Trend Review
a. Inspection Scope (71152 - 1 sample)
The inspectors reviewed Entergys corrective action program database over the last two
calendar quarters of 2003 and the first two quarters of 2004 in order to assess the total
number and significance of CRs written in various subject areas such as equipment and
processes. The results were evaluated on a per quarter basis to identify any notable
trends. The assessment specifically consisted of CR reviews in the following areas:
C Level A CRs: which required a full root cause analysis and review by the
Corrective Actions Review Board (CARB) prior to closeout; and Level B CRs:
which required an apparent cause evaluation and an optional CARB review.
- The number and significance of CRs associated with plant equipment previously
identified as having reliability issues.
- A review of the corrective action database to assess trends in the number of
CRs written in the previous four quarters that were related to subject areas that
reflect the quality of maintenance, work controls, operations, procedures, etc.
- A review of the Indian Point Energy Center Quarterly Integrated Self-
Assessment/Trend Reports for 3Q03, 4Q03, and 1Q04 written by the IPEC
Quality Assurance Department, which contained Entergys assessments of CR
trends during those quarters.
Enclosure
22
b. Findings
No findings of significance were identified.
3. Quarterly Problem Identification and Resolution Review
a. Inspection Scope (71152 - 2 samples)
C CR-IP2-2003-6247: Negative trend in Operations Department configuration
management and controls, potentially impacting mitigating systems operability
and availability. The inspector reviewed the adequacy of the corrective actions
associated with this condition report. The inspector also reviewed CR-IP2-2004-
01746 which identified a similar adverse trend in the number of mispositioning
events. The corrective actions for the latter CR were found to be significantly
more robust and far reaching than the former CR. The inspector determined that
corrective actions were appropriate to address the determined causal factors and
that Entergy was identifying the discrepant issues at a low threshold.
C CR-IP2-2003-7219: Negative trend on overdue preventive maintenance activities
at both IP2 and IP3, potentially having an adverse impact on mitigating systems.
The inspectors assessed the corrective actions documented in related condition
reports CR-IP2-2003-07155 and CR-IP2-2003-07156, and reviewed the trend in
overdue preventive maintenance activities at IP2 for the first six months of 2004.
b. Findings
No findings of significance were identified.
4. Cross-References to PI&R Findings Documented Elsewhere
Inspection findings in previous sections of this report also had implications regarding
Entergys identification, evaluation, and resolution of problems, as follows:
C Section 1R07.2 - Failure to promptly identify and take actions to address a
condition adverse to quality concerning a recirculation sump screen bypass
flowpath and containment debris.
C Section 1R07.3 - Engineering failed to promptly identify and take actions to
address a condition adverse to quality concerning EDG HX fouling.
- Section 1R15.1 - Failure to take adequate corrective actions to resolve issues
associated with voltage reduction on the 13.8 KV system.
Enclosure
23
4OA3 Event Followup
a. Inspection Scope (71153 - 4 samples)
1. (Closed) Licensee Event Report (LER) 2003-004, Automatic Turbine/Reactor Trip Due
to 345kV Grid Disturbance.
NRC inspection observations and findings associated with the event discussed in LER
2003-004, dated October 2, 2003, are documented in Sections 4 and 5 of Inspection
Report 50-247/03-013, dated December 22, 2003. This LER is closed.
2. (Closed) LER 2003-001, Plant in an Unanalyzed Condition due to Cable Routing Non-
Compliance with Appendix R Separation Criteria.
Initial NRC inspector review of the non-conforming condition documented in LER 2003-
001, dated April 2, 2003, was documented in Inspection Report 50-247/03-03, dated
May 13, 2003. Pending further inspector review, an unresolved item was assigned to
this issue (URI 50-247/03-03-01). The unresolved item was reviewed and closed as a
licensee-identified finding in Inspection Report 50-247/04-05. The non-conforming cable
separation condition was identified as low safety consequence, consistent with Appendix
F, Fire Protection SDP. This LER is closed.
3. (Closed) LER 2002-006, Two of Three Emergency Diesel Generators Inoperable Due
to Component Failures: A Condition Prohibited by Technical Specifications.
NRC observations and findings associated with the event discussed in LER 2003-006,
dated December 4, 2002, are documented in Inspection Report 50-247/02-07, dated
February 11, 2003. Entergy appropriately adhered to the Technical Specifications
limiting conditions for operation and there were no violations of NRC requirements
associated with this event. This LER is closed.
4. (Closed) LER 2002-005, Central Control Room Wall Identified as Being in Non-
Conformance with Design Drawings.
NRC inspector review of this licensee-identified original construction/design deficiency
was documented in Inspection Report 50-247/02-07, dated February 11, 2003.
Entergys discovery of this condition was prompted by their extent of condition review for
associated control room west wall fire barrier deficiencies. Entergys corrective actions
for this construction deficiency were determined to be appropriate (reference Inspection
Report 50-247/03-10, dated August 4, 2003). This non-conforming condition was
dispositioned as a licensee-identified violation (see Section 4OA7). This LER is closed.
b. Findings
No findings of significance were identified.
4OA5 Other Activities
Enclosure
24
1. Offsite Power System Operational Readiness
Cornerstones: Initiating Events, Mitigating Systems
a. Inspection Scope (2515/156)
The inspectors performed Temporary Instruction 2515/156, Offsite Power System
Operational Readiness. The inspectors collected and reviewed information pertaining
to the offsite power system specifically relating to the areas of the maintenance rule
(10 CFR 50.65), the station blackout rule (10 CFR 50.63), offsite power operability, and
corrective actions. The inspectors reviewed this data against the requirements of
10 CFR 50 Appendix A General Design Criterion 17, Electric Power Systems, and
Plant Technical Specifications. This information was forwarded to NRR for further
review.
b. Findings
No findings of significance were identified.
2. (Closed) URI 05000247/200402-04: Evaluation of the Frequency limits associated with
the 118 VAC instrument bus and determination of the impact of operating at 60.7 Hz on
risk significant loads.
The inspectors reviewed Entergy evaluation of operating the instrument busses at 60.7
Hz due to an inoperable inverter and the impact this could have on risk significant loads.
It was determined that the acceptable operating range based on the most limiting
components was 57.0-63.0 Hz. Within that frequency range all component output
signals would still be within the required tolerance. It was found that based on original
purchase documents, the most limiting component would only tolerate a +/- 0.6 HZ
deviation but the as delivered equipment was more tolerant of frequency variations and
could therefore maintain its required accuracy over a +/- 3.0 Hz deviation. It was
determined that there was no adverse impact from operating the instrument bus at 60.7
Hz. No violation of NRC requirements was identified. This unresolved item is closed.
4OA6 Meetings, Including Exit
1. Routine Exit Meetings
On the inspectors met with Indian Point 2 representatives to review the
inspection activities. At that time, the purpose and scope of the inspection were
reviewed, and the preliminary results were presented. Entergy acknowledged the
preliminary inspection results.
The inspectors asked Entergy whether any materials examined during the inspection
should be considered proprietary. No proprietary information was reviewed during this
inspection.
Enclosure
25
The inspectors for the Operator Requalification Program presented the inspection
results to members of licensee management at the conclusion of the inspection on
May 28, 2004, and obtained pass/fail results from a licensee representative on
July 6, 2004. No materials reviewed were identified by Entergy as proprietary.
2. Management Site Visits
On July 14, 2004, Ellis Merschoff, Deputy Executive Director of Reactors and Brian
Holian, Deputy Director, Division of Reactor Projects, visited the Indian Point Energy
Center, toured IP2 and IP3 plant areas, and met with senior members of Entergy
Nuclear Northeast, Inc.
4OA7 Licensee-Identified Violation
The following violation of very low safety significance (Green) were identified by the
licensee and is a violation of NRC requirements which meet the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited
violation:
10 CFR 50, Appendix B, Criterion III, states that measures shall be established
to assure that applicable regulatory requirements and design basis for
structures, systems, and components are correctly translated into specifications
and drawings to ensure essential safety-related functions are established and
maintained. Contrary to this requirement, Entergy identified the central control
room south masonry wall did not meet the specific design basis earthquake
requirements as described in the IP2 Final Safety Analysis Report. However, the
seismic qualification of the wall was evaluated by the licensee and determined to
have remained operable, but degraded. This issue was documented in CR
2002-09027 and LER 2002-005, dated February 11, 2003. This licensee-
identified violation was of very low safety significance.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Enclosure
A-1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel:
W. Axelson Radiological Engineering Supervisor
T. Barry Security Superintendent
T. Beasley System Engineering
F. Bloise PI-10 Project Manager
T. Burns NEM/Respiratory Protection Supervisor
R. Christman Supervisor, Nuclear Operator Training
P. Conroy Licensing Manager
F. Dacimo Site Vice President
G. Dahl Senior Licensing Engineer
R. Deschamps Radiation Protection Coordinator
R. DeCensi Technical Support Manager and Radiation Protection Manager
C. English Unit 1 Project Coordinator
D. Gainer Risk Analyst
D. Gately Assistant Radiation Protection Manager
D. Gray Environmental Engineer
P. Gropp Manager DBI Project
G. Hocking Instruments and Dosimetry Supervisor
F. Inzirillo Emergency Preparedness Manager
T. Jones Nuclear Safety/Licensing Specialist, Licensing
M. Kerns Chemistry Manager
R. LaVera ALARA Supervisor
L. Lee System Engineering Supervisor, Support Systems
T. McCaffrey Manager of System Engineering
D. Mayer Unit 1 Project Manager
R. Milici Senior Engineer, Electrical Design Engineering
K. Naku Unit 2 Instrumentation and Controls Assistant Superintendent
J. ODriscoll System Engineer (CCW)
D. Pace Vice President - Engineering Northeast
J. Peters Unit 2 Plant Chemist
S. Petrosi Manager, Design Engineering
J. Raffaele Design Engineering Supervisor - Electrical
R. Robenstein Simulator Support Leader
B. Rokes Senior Licensing Engineer
A. Singer Supervisor, Nuclear Operator Requalification Training
R. Sutton Maintenance Rule Coordinator
J. Toscano System Engineering
J. Tuohy Manager Engineering Support
M. Vasely Engineering Supervisor
R. Walpole Nuclear Manager
C. Wend Radiation Protection Superintendent
D. Wilson Chemistry Assistant Superintendent
Attachment
A-2
B. Young Senior Mechanical Engineer
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened/Closed
NCV 50-247/04-06-01 Failure to implement appropriate design controls during
modifications to the recirculation sump.
NCV 50-247/04-06-02 Failure to identify and correct deficiencies associated with the
recirculation sump.
NCV 50-247/04-06-03 Failure to identify a condition adverse to quality which could
impact EDG reliability.
FIN 50-247/04-06-04 Failure to implement adequate corrective actions for low voltage
conditions on the 13.8 KV system.
NCV 50-247/04-06-05 Failure to implement Technical Specification Surveillance
Requirement SR 3.3.1.1 for channel checks of the feedwater flow
instrumentation.
Closed
LER 2003-004 Automatic Turbine/Reactor Trip Due to 345kV Grid Disturbance.
LER 2003-001 Plant in an Unanalyzed Condition due to Cable Routing Non-
Compliance with Appendix R Separation Criteria.
LER 2002-006 Two of Three Emergency Diesel Generators Inoperable Due to
Component Failures: A Condition Prohibited by Technical
Specifications.
LER 2002-005 Central Control Room Wall Identified as Being in Non-
Conformance with Design Drawings.
URI 50-247/04-02-04 Static inverter frequency specification for operability.
Attachment
A-3
LIST OF BASELINE INSPECTIONS PERFORMED
71111.04 Equipment Alignment 1R04
71111.05 Fire Protection 1R05
71111.06 Flood Measures 1R06
71111.07 Heat Sink Performance 1R07
71111.11 Operator Requalification 1R11
71111.12 Maintenance Effectiveness 1R12
71111.13 Maintenance Risk Assessment and Emergent Work Activities 1R13
71111.14 Personnel Performance During Non-Routine Plant Evolutions 1R14
71111.15 Operability Evaluations 1R15
71111.19 Post Maintenance Testing 1R19
71111.22 Surveillance Testing 1R22
71111.23 Temporary Plant Modifications 1R23
71114.06 Emergency Plan Drill 1EP6
71151 Performance Indicator Verification 4OA1
71152 Problem Identification and Resolution Sample 4OA2
71153 Event Followup, LERs, Open Items 4OA3
LIST OF DOCUMENTS REVIEWED
Section 1R04: Equipment Alignment
Clearance 2C16
Tagout 2-480V-MCC26B-6MR (MOV887B) Bucket PM
Tagout 2-480V-MCC26B-4DR (MOV851B) Bucket PM
Tagout 2-480V-22SIP 2A Breaker EM
Section 1R05: Fire Protection
Fire Protection Implementation Plan, Pre-Fire Plans
Station Administrative Order (SAO)-700, Fire Protection and Prevention Policy,
SAO-703,
ENN-DC-161, Transient Combustible Program.
Section 1R06: Flood Protection Measures
IPEEE, Section 5
2AOP-FLOOD-1, Flooding
Background Document for 2AOP-FLOOD-1
Operations Document Feedback IP2-4826
Attachment
A-4
Section 1R07: Heat Sink Performance
89-13 Program and Design Basis Documents
WCAP-12313, Safety Evaluation for an Ultimate Heat Sink Temperature Increase to 950F at
Indian Point Unit 2, Rev. 2, dated January 2004
Consolidated Edison Letter, Stephen B. Bram to the NRC, dated February 2, 1990, Service
Water System Problems Affecting Safety Related Equipment
Consolidated Edison Letter, Stephen B. Bram to the NRC, dated July 19, 1991, Implementation
Status of Generic Letter 89-13 Required Actions
EPRI NP-7552, Heat Exchanger Performance Monitoring Guidelines, December 1991
EPRI TR-107397, Service Water Heat Exchanger Testing Guidelines, March 1998
Corrective Action Documents (CR-IP2-20XX)
01-05679 02-08272 03-00912 03-06197 04-01416
02-05311 02-09667 03-02592 03-06539 04-01781
02-05637 02-10749 03-03166 04-00277 04-01820
02-06897 02-10853 03-03741 04-00341 04-08597
02-06905 03-00860 03-04192 04-00450 04-08931
02-07065 03-00886 03-04618 04-00998
Engineering Evaluations and Calculations
TA-03-2-111-001, Remove Internals From S.W. Strainer Blowdown Valves
TA-04-2-078, Install Clamps on Pipe Collars Around Recirc Pump 21 and 22 Bypass
PGI-00186-00, Test Data and Analysis for IP2 Safety Injection Pump Lube Oil Cooler
Performance, Rev. 0
PGI-00219-00, RHR Heat Exchangers Performance - 1996, dated 11/8/96
PGI-00354-02, Generic Letter 89-13 Heat Exchanger Performance Assessment Program,
dated 1/11/01
FMX-00295-00, Tube Plugging Limits for EDG Lube Oil Coolers and Jacket Water Coolers, Rev.
0
FMX-00142-00, Study the Effect of LOCA Generated Debris on ECCS Performance, dated
12/22/1999
EDG Testing and Inspections
SE-330 Inspection Report for 21 EDG HXs, dated 2/16/03
SE-330 Inspection Report for 21 EDG HXs, dated 6/16/03
SE-330 Inspection Report for 21 EDG HXs, dated 2/24/04
SE-330 Inspection Report for 22 EDG HXs, dated 10/27/02
SE-330 Inspection Report for 22 EDG HXs, dated 4/23/03
SE-330 Inspection Report for 22 EDG HXs, dated 3/23/04
SE-330 Inspection Report for 23 EDG HXs, dated 1/7/02
SE-330 Inspection Report for 23 EDG HXs, dated 5/19/03
Attachment
A-5
Record of Eddy Current Inspection of Emergency Diesel Generator 21 Lube Oil Cooler & Jacket
Water Cooler at IP2, dated 2/25/03
Record of Eddy Current Inspection of Emergency Diesel Generator 22 Lube Oil Cooler & Jacket
Water Cooler at IP2, dated 10/2/02
Record of Eddy Current Inspection of Emergency Diesel Generator 23 Lube Oil Cooler & Jacket
Water Cooler at IP2, dated 11/6/02
PT-R84A, 21 EDG 8 Hour Load Test, dated 11/18/02
PT-R84B, 22 EDG 8 Hour Load Test, dated 11/19/02
PT-R84C, 23 EDG 8 Hour Load Test, dated 11/17/02
2-PT-M021A, Emergency Diesel Generator 21 Load Test, dated 3/22/04
2-PT-M021B, Emergency Diesel Generator 22 Load Test, dated 3/23/04
2-PT-M021C, Emergency Diesel Generator 23 Load Test, dated 3/24/04
Miscellaneous
Unit 3 Service Water Intake Pump Bay Silt Mapping, dated 7/23/01
Unit 3 Service Water Intake Pump Bay Silt Mapping, dated 2/9/04
NRC Information Notice 2004-07: Plugging of Safety Injection Pump Lubrication Oil Coolers With
Lakeweed, dated 4/7/04
PI-M2, Containment Building Inspection, Rev. 18
QS-2004-IP-004, Quality Assurance Surveillance Report, Preparations Review for NRC Heat
Sink Inspection, dated 4/12/04
IP3-LO-2004-00167, IPEC Focused Self-Assessment, Indian Point Unit 2 Ultimate Heat Sink,
dated 4/09/04
IP2 Chlorination Sample Results 1/1/03 - 9/11/03
Indian Point 2 - NRC Inspection Report No. 50-247/02-03
2003 Indian point Zebra Mussel Monitoring program Report, dated 12/18/03
2-PT-Q90, Component Cooling Water System Quarterly Alignment Verification, dated 2/22/04
Safety Assessment of the Recirculation and Containment Sumps for Indian Point Station Unit 2,
dated May 1995
Risk-Informed Inspection Notebook for Indian Point Nuclear Power Plant, Unit 2, Revision 1
Procedures
STR-P-004A, IP2 Zurn Service Water Strainers (Preventive Maintenance), Rev. 5
STR-B-003A, IP2 Zurn Spare Service Water Strainer Overhaul, Rev. 11
SOP 27.3.1.2, Emergency Diesel Generator Manual Operation, Attachment 1, Post-Run Line-up
Verification, Rev. 14
SE-330, Service Water Inspection Standard, Rev. 3
SAO-213, Containment Entry, Egress and Inspection, Rev. 5
2-AOP-SW-1, Service Water Malfunction, Rev. 2
2-COL 24.1.1, Service Water and Closed Cooling Water Systems, Rev. 36
2-COL 4.1.1, Component Cooling System, Rev. 20
COL 24.1.2, Service Water Essential Header Verification, Rev. 14
OSP 24.1, Support Procedure - Service Water System Operation, Rev. 4
SOP 24.1, Service Water System Operation, Rev. 52
SOP 24.1.1, Service Water Hot Weather Operations, Rev. 9
Attachment
A-6
2-CY-3172, Zebra Mussel Monitoring, Rev. 0
SOP-RW-007, Circulating and Service Water Sodium Hypochlorite Injection System, Rev. 26
PT-Q28A, 21 Residual Heat Removal Pump, dated 3/30/04
PT-Q28B, 22 Residual Heat Removal Pump, dated 1/24/04
PT-Q29A, 21 Safety Injection Pump, dated 3/1/04
PT-Q29B, 22 Safety Injection Pump, dated 3/29/04
PT-Q29C, 23 Safety Injection Pump, dated 1/20/04
SW Testing
PT-Q26A, 21 Service Water Pump, dated 2/16/04
PT-Q26B, 22 Service Water Pump, dated 3/8/04
PT-Q26C, 23 Service Water Pump, dated 3/15/04
PT-Q26D, 24 Service Water Pump, dated 4/5/04
PT-Q26E, 25 Service Water Pump, dated 2/5/04
PT-Q26F, 26 Service Water Pump, dated 2/13/04
PT-3Y9, Flow Test For Underground Service Water Line 408, dated 8/21/02
PT-3Y10, Flow Test For Underground Service Water Line 409, dated 9/3/02
System Health
Maintenance Rule Program Quarterly Report (First Quarter 2004)
Unit 2 Service Water System Health Report (Fourth Quarter 2003)
Unit 2 Safety Injection System Health Report (Fourth Quarter 2003)
Unit 2 Residual Heat Removal System Health Report (Fourth Quarter 2003)
Unit 2 Emergency Diesel Generators Health Report (Fourth Quarter 2003)
Work Orders (IP2)
01-23308 00-14369 03-13430 04-17509 03-17921
02-48726 03-10440 03-16606 03-16602
Section 1R19: Post-Maintenance Testing
Attachment
A-7
Section 1R22: Surveillance Testing
WO No. IP2-03-21761
WRT No. IP2-04-20762
CR-IP2-2004-02644
Section 1R23: Temporary Plant Modifications
ENN-LI-101, 10 CFR 50.59 Review Process
WO No. IP2-04-18017
WO No. IP2-04-18146
WO No. IP2-04-18178
WO No. IP2-04-18321
WO No. IP2-04-18268
Section 4OA1: Performance Indicator Verification
1PC-S-009-S Primary Sampling System Sentry
NL-04-036 Indian Point Unit 2 - 1Q2004 - PI Data Elements (QR)
NL-04-008 Indian Point Unit 2 - 4Q2003 - PI Data Elements (QR) and Change Report
(CR) for 2Q2003 and 2Q2003
NL-03-163 Indian Point Unit 2 - 3Q2003 - PI Data Elements (QR)
NL-03-122 Indian Point Unit 2 - 2Q2003 - PI Data Elements (QR)
NL-03-065 Indian Point Unit 2 - 1Q2003 - PI Data Elements (QR)
Indian Point 2 Narrative Operating Logs for 1Q2003 through 1Q2004
Section 4OA2: Identification and Resolution of Problems
CR-IP2-2003-07155
Attachment
A-8
LIST OF ACRONYMS
CAP corrective action program
CARB Corrective Actions Review Board
CCW component cooling water
CFR Code of Federal Regulation
COL check off list
CR condition report
ECCS emergency core cooling system
EDG emergency diesel generator
EOF emergency operations facility
EP emergency planning
EPRI Electric Power Research Institute
GT gas turbine
HX heat exchanger
IMC inspection manual chapter
IP Indian Point
IP2 Indian Point Unit 2
IPEC Indian Point Energy Center
IPEEE Individual Plant Examination for External Events
ITS improve technical specifications
JW jacket water
LOCA loss-of-coolant accident
NCV non-cited violation
NEI Nuclear Energy Institute
NRC Nuclear Regulatory Commission
OA other activities
OE operating experience
OS occupational radiation safety
OSC operations support center
PAB primary auxiliary building
PI performance indicator
PWR pressurized water reactor
PWT post work test
SAO station administrative orders
SCBA self-contained breathing apparatus
SDP significance determination process
SE safety evaluation
SI safety injection
SOP system operating procedure
TA temporary alteration
TS technical specifications
UFSAR Updated Final Safety Analysis Report
Attachment
A-9
VC vapor containment
WO work order
Attachment