ML031340032
ML031340032 | |
Person / Time | |
---|---|
Site: | Indian Point |
Issue date: | 05/13/2003 |
From: | Brian Holian Division of Nuclear Materials Safety I |
To: | Dacimo F Entergy Nuclear Operations |
References | |
FOIA/PA-2003-0379, FOIA/PA-2003-0388, FOIA/PA-2004-0042 IR-03-003 | |
Download: ML031340032 (46) | |
See also: IR 05000247/2003003
Text
May 13, 2003
Mr. Fred Dacimo
Vice President - Operations
Entergy Nuclear Operations, Inc.
Indian Point Nuclear Generating Units 1 & 2
295 Broadway, Suite 1
Post Office Box 249
Buchanan, NY 10511-0249
SUBJECT: INDIAN POINT 2 - NRC INTEGRATED INSPECTION REPORT 50-247/03-03
Dear Mr. Dacimo:
On March 29, 2003, the US Nuclear Regulatory Commission (NRC) completed an inspection at
the Indian Point 2 Nuclear Power Plant. The enclosed integrated inspection report documents
the inspection findings, which were discussed on April 9, 2003, with yourself and other members
of your staff.
The inspections examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, the inspectors identified four findings of very low safety
significance (Green), all of which were determined to be violations of NRC requirements.
However, because of their very low safety significance and because the issues have been
addressed and entered into your corrective action program, the NRC is treating these issues as
Non-Cited Violations, in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you
deny these Non-Cited Violations, you should provide a response with the basis for your denial,
within 30 days of the receipt of this letter, to the Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, D.C. 20555-001; with copies to the Regional
Administrator, Region 1; the Director, Office of Enforcement; and the NRC Resident Inspector at
the Indian Point 2 facility.
Since the terrorist attacks on September 11, 2001, the NRC has issued five Orders (dated
February 25, 2002, January 7, 2003, and three on April 29, 2003) and several threat advisories
to licensees of commercial power reactors to strengthen licensee security capabilities, improve
security force readiness and training, and enhance access authorization. The NRC also issued
Temporary Instruction 2515/148 on August 28, 2002, that provided guidance to inspectors to
audit and inspect licensee implementation of the interim compensatory measures (ICMs)
required by the February 25th Order. Phase 1 of TI 2515/148 was completed at all commercial
nuclear power plants during calendar year (CY) 02, and the remaining inspections are
scheduled for completion in CY 03. Additionally, table-top security drills were conducted at
several licensees to evaluate the impact of expanded adversary characteristics and the ICMs on
licensee protection and mitigative strategies. Information gained and discrepancies identified
Mr. Fred Dacimo 2
during the audits and drills were reviewed and dispositioned by the Office of Nuclear Security
and Incident Response. For CY 03, the NRC will continue to monitor overall safeguards and
security controls, conduct inspections, and resume force-on-force exercises at selected power
plants. The Indian Point site will receive a pilot force-on-force exercise this summer. Should
threat conditions change, the USNRC may issue additional Orders, advisories, and temporary
instructions to ensure adequate safety is being maintained at all commercial power reactors.
The inspectors reviewed eight effectiveness reviews associated with the Fundamental
Improvement Plan (FIP). The FIP was an improvement plan initiated in early 2002 in response
to the NRCs classification of Indian Point Unit 2 as a multiple degraded cornerstone column
facility. The effectiveness reviews evaluated the quality of corrective actions in specific areas
and concluded if those actions had improved performance. Specific areas evaluated included:
management observation of work activities; operator burden and work-down curve for temporary
alterations; review of the design basis initiative project; optimization of the preventive
maintenance program; corrective actions in monitoring the work control process; equipment
reliability actions; work management self-assessments; and corrective action effectiveness
reviews for condition reports. The inspectors concluded that the effectiveness reviews were not
uniformly self-critical or consistent with recent NRC assessments or performance metrics. For
example, the effectiveness review for the design basis initiative project primarily focused on the
quality of action plans and efficiencies of plan implementation, instead of the quality of the
engineering staffs products or recently developed design information road maps. However,
the inspectors did note that the 2003 Indian Point Business Plan does provide appropriate
actions to support improvements in the key areas addressed in the FIP. Your attention to the
quality of self-assessments remains an important element to continued station improvement.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document Room
or from the Publicly Available Records (PARS) component of the NRCs document system
(ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-
rm/adams.html (the Public Electronic Reading Room). Should you have any questions
regarding this report, please contact Mr. Peter Eselgroth at 610-337-5234.
Sincerely,
/RA/
Brian E. Holian, Deputy Director
Division of Reactor Projects
Docket No.50-247
License No. DPR-26
Enclosure: Inspection Report 50-247/03-03
W/Attachment: Supplemental Information
cc w/encl: G. J. Taylor, Chief Executive Officer, Entergy Nuclear
M. R. Kansler, President - Entergy Nuclear Northeast
Mr. Fred Dacimo 3
J. Herron, Senior Vice President, Indian Point Energy Center
C. Schwarz, General Manager - Plant Operations
D. Pace, Vice President, Engineering
J. Knubel, Vice President, Operations Support
J. McCann, Manager, Nuclear Safety and Licensing
J. Kelly, Director, Nuclear Safety Assurance
C. Faison, Manager, Licensing
H. Salmon, Jr., Director of Oversight
J. Fulton, Assistant General Counsel, Entergy Nuclear Operations, Inc.
W. Flynn, President, New York State Energy, Research
and Development Authority
J. Spath, Program Director, New York State Energy Research
and Development Authority
P. Eddy, Electric Division, New York State Department of Public Service
C. Donaldson, Esquire, Assistant Attorney General, New York Department
of Law
T. Walsh, Secretary, NFSC, Entergy Nuclear Operations, Inc.
D. ONeill, Mayor, Village of Buchanan
J. G. Testa, Mayor, City of Peekskill
R. Albanese, Executive Chair, Four County Nuclear Safety Committee
S. Lousteau, Treasury Department, Entergy Services, Inc.
Chairman, Standing Committee on Energy, NYS Assembly
Chairman, Standing Committee on Environmental Conservation, NYS Assembly
Chairman, Committee on Corporations, Authorities, and Commissions
M. Slobodien, Director, Emergency Planning
B. Brandenburg, Assistant General Counsel
P. Rubin, Operations Manager
Assemblywoman Sandra Galef, NYS Assembly
C. Terry, Niagara Mohawk Power Corporation
County Clerk, Westchester County Legislature
A. Spano, Westchester County Executive
R. Bondi, Putnam County Executive
C. Vanderhoef, Rockland County Executive
E. A. Diana, Orange County Executive
T. Judson, Central NY Citizens Awareness Network
M. Elie, Citizens Awareness Network
D. Lochbaum, Nuclear Safety Engineer, Union of Concerned Scientists
Public Citizen's Critical Mass Energy Project
M. Mariotte, Nuclear Information & Resources Service
F. Zalcman, Pace Law School, Energy Project
L. Puglisi, Supervisor, Town of Cortlandt
Congresswoman Sue W. Kelly
Congresswoman Nita Lowey
Senator Hilary Rodham Clinton
Senator Charles Schumer
J. Riccio, Greenpeace
A. Matthiessen, Executive Director, Riverkeepers, Inc.
M. Kapolwitz, Chairman of County Environment & Health Committee
A. Reynolds, Environmental Advocates
Mr. Fred Dacimo 4
M. Jacobs, Director, Longview School
D. Katz, Executive Director, Citizens Awareness Network
P. Gunter, Nuclear Information & Resource Service
P. Leventhal, The Nuclear Control Institute
K. Copeland, Pace Environmental Litigation Clinic
R. Witherspoon, The Journal News
Mr. Fred Dacimo 5
Distribution w/encl: H. Miller, RA/J. Wiggins, DRA (1)
H. Nieh, RI EDO Coordinator
P. Habighorst, SRI - Indian Point 2
R. Laufer, NRR
P. Eselgroth, DRP
W. Cook, DRP
R. Junod, DRP
R. Martin, DRP
Region I Docket Room (w/concurrences)
DOCUMENT NAME: C:\ORPCheckout\FileNET\ML031340032.wpd
After declaring this document An Official Agency Record it will be released to the Public. To
receive a copy of this document, indicate in the box: "C" = Copy without
attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy
OFFICE RI/DRP RI/DRP E RI/DRP E
NAME PHabighorst/PWE for PEselgroth/PWE BHolian/BEH
DATE 05/13/03 05/13/03 05/13/03
OFFICIAL RECORD COPY
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No. 50-247
License No. DPR-26
Report No. 50-247/03-03
Licensee: Entergy Nuclear Operations, Inc.
Facility: Indian Point 2 Nuclear Power Plant
Location: Buchanan, New York 10511
Dates: December 29, 2002 - March 29, 2003
Inspectors: Peter Habighorst, Senior Resident Inspector
Lois James, Resident Inspector
Jason C. Jang, Senior Health Physicist (1/6-1/10/03)
William Cook, Senior Project Engineer (3/10-3/14/03)
David Silk, Emergency Preparedness Specialist (1/6-29/03)
Daniel Barss, Emergency Preparedness Specialist (1/6-29/03),
Thomas Burns, Senior Reactor Engineer, DRS (2/10-2/13/03)
John R. McFadden, Health Physicist, DRS (2/24-2/28/03)
Leonard Cheung, Sr. Reactor Engineer, DRS (11/4-11/9/02)
Approved by: Peter W. Eselgroth, Chief
Projects Branch 2
Division of Reactor Projects
i Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
SUMMARY OF PLANT STATUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R06 Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1R11 Operator Requalification Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R13 Maintenance Risk Assessment and Emergent Work Activities . . . . . . . . . . . . . . 8
1R14 Personnel Performance During Non-Routine Plant Evolutions and Events . . . 11
1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
1R17 Permanent Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
1R19 Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
1EP4 Emergency Action Level and Emergency Plan Changes . . . . . . . . . . . . . . . . . 17
1EP6 Emergency Plan Drills . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
2. RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
2OS1 Access Control to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 18
2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
2OS3 Radiation Monitoring Instrumentation and Protective Equipment . . . . . . . . . . . 20
2PS1 Gaseous and Liquid Effluents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
2PS2 Radioactive Material Processing and Transportation . . . . . . . . . . . . . . . . . . . . 22
4. OTHER ACTIVITIES (OA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
4OA3 Event Follow-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
4OA5 Review of Institute of Nuclear Power Operations (INPO) Evaluation Report . . 29
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
ATTACHMENT: SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
LIST OF BASELINE INSPECTIONS PERFORMED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
ii Enclosure
SUMMARY OF FINDINGS
IR 05000247-03-03, on December 29, 2002 - March 29, 2003, Entergy Nuclear Operations, Inc.;
Indian Point 2 Nuclear Power Plant; Maintenance Risk Assessment/Emergent Work, Post
Maintenance Testing; and Radioactive Material Processing and Transportation.
The report covered a twelve-week period of inspection by resident, region-based, and
headquarters-based inspectors. Four Green non-cited violations (NCVs), and two unresolved
items were identified. The significance of the findings are indicated by their color (Green, White,
Yellow, Red) in accordance with Inspection Manual Chapter (IMC) 0609, Significance
Determination Process (SDP). The NRCs program for overseeing the safe operation of
commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 3, dated July, 2000.
A. NRC- Identified and Self-Revealing Findings
Cornerstone: Initiating Events
- Green. On February 7, 2003, a self-revealing finding involved inadequate
emergent work instructions that resulted in an electrical short during replacement
of the 22 steam generator low level bistable. The electrical short caused a
breaker trip on circuit 10 of instrument bus 21and the resultant loss of electrical
power to the pressurizer level and reactor coolant system pressure control
channels (failed low). The inadequate work instructions is considered a non-cited
violation of 10 CFR 50 Appendix B, Criterion V, since the instructions did not
account for consideration of performing this replacement with the circuit de-
energized or the proximity to other reactor protection system relays.
The performance issue is more than minor since the operators were required to
take action to restore reactor coolant system pressure and pressurizer level to
preclude a reactor trip. The finding involves the initiating events cornerstone in
that it increased the likelihood of upset in plant stability and it involves human
error during the planning of an emergent work activity. This finding is considered
to be of very low safety significance in that in accordance with NRC Manual
Chapter 0609, Appendix A, the finding did not contribute to the likelihood of a
secondary or primary LOCA initiator and it did not contribute to either a reactor
trip or mitigation system unavailability. (Section 1R13)
Cornerstone: Mitigating Systems
- Green. A self-revealing event was identified on February 26, 2003, when
operators observed no boric acid flow to the reactor vessel via the No. 22 boric
acid transfer pump (BATP). It was determined that during preventative
maintenance activities in March 2001, the post-work test on the No. 22 BATP
outlet valve to the boric acid filter stop was inadequate to identify that the valve
finger plate was installed upside down. This finding is considered a non-cited
violation of 10 CFR 50 Appendix B, Criterion V. This event is considered more
than minor because the improperly installed valve plate affected the availability of
one train of emergency boration. This is considered to be of very low risk
iii Enclosure
Summary of Findings (contd)
significance in accordance with NRC MC 0609 Appendix A, since the emergency
boration function was not lost due to this performance issue. (Section 1R19)
- Green. The inspectors identified that ineffective corrective actions resulted in
repetitive surveillance test failures of the 23 emergency diesel generator between
December 2001 and February 2003. This finding is considered a non-cited
violation of 10 CFR 50, Appendix B, Criterion XVI. The finding is more than minor
because the surveillance test failures impacted the availability of one train of
emergency AC power source. This finding was of very low risk significance
because the repetitive failures did not result in an actual loss of function for the
emergency AC power. (Section 1R13)
Cornerstone: Public Safety
- Green. A self-revealing non-cited violation of 10 CFR 71.12 was identified for
failure to comply with shipping cask package procedures. On February 6, 2003, a
CNS 8-120 B cask was received from the Indian Point Energy Center at a
consolidation facility in South Carolina with a bolt missing on the primary lids
pressure test port in violation of the cask use and maintenance procedures. This
finding was more than minor in that it was associated with the Public Radiation
Safety Cornerstones attribute of procedures for transportation packages. The
finding affected the associated cornerstone objective to ensure adequate
protection of public health and safety from exposure to radioactive materials
contained in an NRC-approved Type B package released into the public domain.
The finding was determined to be of very low safety significance in that the finding
did not involve exceeding transportation radiation limits, there was no breach of
the package during transit, and the issue was a Certificate of Compliance
maintenance/use performance deficiency. (Section 2PS2)
iv Enclosure
REPORT DETAILS
SUMMARY OF PLANT STATUS
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity and Emergency
Planning
1R04 Equipment Alignment
a. Inspection Scope
.1 Partial System Walkdowns
On January 23, 2003, the inspector performed a partial system walkdown of the 22
auxiliary feedwater pump (AFWP) train while the 23 AFWP train was out of service for
preventive maintenance. The purpose of this walkdown was to verify equipment
alignment and identify any discrepancies that could adversely impact the function of the
steam driven auxiliary feedwater pump train. The inspector observed the physical
condition of the system pump and valves and reviewed the operations logs. The
inspector used check-off lists (COLs) 21.3, Steam Generator Water Level and Auxiliary
Boiler Feedwater and 18.1, Main and Reheat Steam, for this walkdown and reviewed
the design basis document for the auxiliary feedwater system and Technical Specification 3.4 to verify the valve positions, as defined in the COL, were appropriate.
On February 25, 2003, the inspector performed a system walkdown of the fuel oil portion
of the emergency diesel generator (EDG) system while the 21 EDG was out of service
for preventive maintenance. The purpose of this walkdown was to verify equipment
alignment and identify any discrepancies that could adversely impact the operation of the
remaining EDGs and thereby increase risk. The inspector observed the physical
condition of the fuel oil system pumps and valves. The inspector used COL 27.3.1,
Diesel Generators, for this walkdown and reviewed the design basis document for the
diesel generator fuel oil system.
On March 11, 2003, the inspector performed a system walkdown of the 21 containment
spray system while the 22 containment spray pump was out of service for planned testing
and preventative maintenance. The purpose of this walkdown was to verify equipment
alignment and identify any discrepancies that could adversely impact the function of the
containment spray system and thereby increase risk. The inspector observed the
physical condition of the containment spray pump and valves. The inspector used COL
10.2.1, Containment Spray System, system operating procedure (SOP) 10.2.1,
Containment Spray System Operation, and plant drawings 9321-F-2735-130 and
A225296. Minor deficiencies involving plant labeling and plant drawing errors were
provided to the licensee and addressed via the corrective action process. The
inspectors review of an operability determination for the containment pressure
instruments is documented in report section 1R15.
b. Findings
Enclosure
2
No findings of significance were identified.
.2 Full System Alignment
a. Inspection Scope
The inspector performed a walkdown of accessible portions of the engineered
safeguards features system (ESFS) to verify electrical separation between channels and
identify any discrepancies that may adversely impact the function of the system. The
inspector also verified that the licensee had properly identified and resolved equipment
problems that could impact the availability and functional capability of this accident
mitigation system. The inspector selected the ESFS based upon its importance to plant
safety and risk. This system is in the top twenty systems at the unit based upon risk
achievement worth (which measures the relative risk of systems based on IPE data).
The inspector reviewed the following documents to confirm system availability and
functional capability:
- The Technical Specifications for the ESFS, Section 3.5.3
- Maintenance Rule Background Document for ESFS
- Outstanding elective and corrective maintenance activities associated with ESFS
- Outstanding control room deficiencies associated with ESFS
- Last completed Technical Specification surveillances: PC-R4, Pressurizer
Pressure; PC-R4-1, Pressurizer Pressure Transmitters; PT-Q55, Pressurizer
Pressure; PC-R29, Main Steam Line Flow Instrumentation - CCR; PT-Q63,
Steam Flow/Feedwater Flow Mismatch Bistables; and PC-R32-1, Main Feedwater
Flow - Transmitters;
- System Engineering Health Reports for ESFS for 4th quarter of 2002
- SE-350 Attachment 8.2, System Monitoring Basis Document for ESFS
- Design Basis Document for Engineered Safeguards Feature System
- Abnormal Operating Instruction 10.1.4, Safeguards Relays DC Power Failure
- Condition Report IP2-2003-01026
b. Findings
No findings of significance were identified.
Enclosure
3
1R05 Fire Protection
.1 Fire Zone Tours
a. Inspection Scope
The inspector toured the areas important to plant safety and risk based upon a review of
Section 4.0, Internal Fires Analysis, and Table 4.6-2, Summary of Core Damage
Frequency Contributions from Fire Zones, in the Indian Point 2 Individual Plant
Examination for External Events (IPEEE). The objective of this inspection was to
determine if the licensee had adequately controlled combustibles and ignition sources
within the plant, effectively maintained fire detection and suppression capability, and had
adequately established compensatory measures for degraded fire protection equipment.
The inspector evaluated conditions related to: (1) licensee control of transient
combustibles and ignition sources; (2) the material condition, operational status, and
operational lineup of fire protection systems, equipment and features; and (3) the fire
barriers used to prevent fire damage or fire propagation. The areas reviewed were:
- Fire Zone 63A, circulating water pumps area
- Fire Zone 610, Unit 1 screenwell room
- Fire Zone 14, auxiliary feedwater pump room
- Fire Zone 23, 480V switchgear room
- Fire Zone 6A, Waste Storage and Drumming Station
- Fire Zone 74A and 74B, Electrical Penetration Areas of the Fan House
- Fire Zone 7A, 80-foot elevation of Primary Auxiliary Building
- Fire Zone 43A, 15-foot elevation of Turbine Building
Reference material consulted by the inspector included the Fire Protection
Implementation Plan, Pre-Fire Plan, and Station Administrative Order (SAO)-700, Fire
Protection and Prevention Policy, SAO-701, Control of Combustibles and Transient Fire
Load, SAO-703, Fire Protection Impairment Criteria and Surveillance, and Calculation
PGI-00433, Combustible Loading Calculation. The inspector identified a number of
minor items related to drawing errors in the pre-fire plan sketch, and penetration drawing
errors and housekeeping concerns. The associated condition reports for these minor
errors are identified in the Attachment to this inspection report.
b. Findings
No findings of significance were identified.
Enclosure
4
.2 Lack of Cable Separation in Fire Areas F and J
a. Inspection Scope
On February 6, 2003, Entergy identified that the routing of charging pump power supply
and control cables do not meet the cable separation criteria specified in 10 CFR 50
Appendix R,Section III.G.1. This was reported to the NRC via 10 CFR 50.72(b)(3)(ii)(B)
(Event Notification 39571) as an unanalyzed condition and documented in condition
report IP2-2003-00765. A postulated fire in Fire Area F (fire zones 6, 7 and 7A) would
disable all three charging pumps. The postulated fire could result in the loss of: the
23 charging pump alternate power feed transfer switch; 23 charging pump alternate
power feed; the alternate/normal power feed cable between the transfer switch and the
pump; 22 charging pump power feed cable; local/remote control cabling (disabling
remote operation of all charging pump breakers); and the control cables and pneumatics
for the 22 and 23 charging pumps.
This design vulnerability was identified by Entergy during a re-baseline analysis to
validate compliance with 10 CFR 50 Appendix R. Entergys review was being performed
under a design basis initiative project (DBI-PI-1) in response to previously identified
concerns about the analysis. Efforts include the location of all Appendix R credited
equipment, power, control and instrument cables, power sources, local controls and
indication, and other features by fire area and fire zone.
On February 12, 2003, Entergy identified that the normal and emergency power supplies
to the six service water pumps were routed through manhole 23 (Unit 2 turbine building
under the 15 elevation) and are completely separated from the fire area except for
manhole 23. The alternate safety shutdown power cables run approximately 200 feet to
the south. The alternate power supply cables for two of the six service water pumps are
routed unprotected from Fire Area J through Fire Area A at the south end of the Unit 1
turbine building. The vulnerability is a postulated fire in Fire area J that could result in a
complete loss of power to all service water pumps. This was reported to the NRC as an
undated to Event Notification 39571. Condition Report IP2-2003-867 documented this
deficiency.
The inspector reviewed and verified that licensee compensatory measures for the
vulnerabilities in Fire Areas F and J were consistent with SAO-703, Fire Protection
Impairment Criteria and Surveillance, Addendum I, item 9. The inspector walked down
the areas to confirm Entergys conclusions regarding the fire vulnerability. The inspector
reviewed the following documents:
- Abnormal Operating Instruction (AOI)27.1.9, Control Room Inaccessibility Safe
Shutdown Control
- OASL 15.11, Attachment 1, 480 Volt DB-50 Breaker Operations
- Individual Plant Examination for External Events (IPEEE)
b. Findings
Enclosure
5
The licensee-identified postulated fire vulnerabilities within Fire Zones F and J are
considered unresolved (URI 50-247/03-03-01). A preliminary assessment of these cable
separation discrepancies identifies them as low safety consequence, based upon:
previous inspection review of the alternate safe shutdown capability and fire protection
program implementation (reference inspection report No. 50-247/2000-004, dated
May 17, 2001); low combustible loading in the affected fire zones; appropriate
compensatory measures in place until final resolution; and low risk significance based
upon current IPEEE analysis of the affected fire zones. This issue will remain unresolved
pending the completion of the NRC/industry review and resolution of issues affecting
safe shutdown associated circuits and manual actions. As discussed above, these
issues have been placed into the licensees corrective action process.
1R06 Flood Protection Measures
a. Inspection Scope
The inspectors reviewed Entergys external flood analysis, flood mitigation procedures,
and design features to verify whether they were consistent with the IP2's design
requirements. The inspectors walked down selected external plant areas, including
areas for large on-site tanks that contain equipment important to safety. The inspectors
evaluated the condition and adequacy of mitigation equipment to assess whether the
flood protection design features were adequate and operable. During the walk downs,
the inspectors also evaluated whether there were any unidentified or unanalyzed sources
of flooding. The specific areas included:
- Service Water Strainer Pit
- Unit 2 Condensate Storage Tanks
- Refueling Water Storage Tank
The inspectors reviewed Entergys flood mitigation procedures, flood alarm response
procedures, and selected preventive maintenance tasks and surveillance tests for the
sump pump in the service water strainer pit to evaluate whether component functionality
was routinely verified. In addition, the inspectors reviewed Entergys corrective action
program to verify whether previous flood related issues had been appropriately identified,
evaluated, and resolved. The following procedures were included in the review:
- Individual Plant Examination for External Events (IPEEE) Section 6.0 External
Flooding
- Updated Final Safety Analysis Report (UFSAR) Section 2.5 Hydrology
- AOI 28.0.6, Nuclear Side (outside containment) Flooding
- AOI 28.0.4, Flooding - Conventional Plant
- AOI 24.1, Service Water Malfunction
b. Findings
No findings of significance were identified.
Enclosure
6
1R11 Operator Requalification Inspection
a. Inspection Scope
On March 3, 2003, the inspector observed the performance of an operating crew during
licensed operator re-qualification training. Specifically, the inspector observed simulator
as-found exams associated with lesson plan SS.700.032. The inspection was
conducted to assess the adequacy of the training, licensed operator performance,
emergency plan implementation, and the adequacy of the licensees critique.
b. Findings
No findings of significance were identified. The operating crew satisfactorily completed
the simulator scenario critical task. The crew critique and the evaluators assessment
were consistent with the inspectors observation of crew performance. Performance
issues associated with the crew involved abnormal operating instruction and emergency
operating procedure inconsistent usage and adherence, and recognition of applicable
Technical Specifications associated with an instrument failure. The crew initiated a
performance improvement plan to improve use of emergency operating procedure and
abnormal operating procedure attachments.
1R12 Maintenance Effectiveness
.1 22 Component Cooling Water
a. Inspection Scope
The inspectors evaluated Entergys work practices and preventive maintenance activities
for the 22 component cooling water (CCW) pump to assess the effectiveness of
maintenance activities. The inspectors reviewed the performance history of the 22 CCW
pump to assess the adequacy of the licensee's corrective actions and to evaluate
Entergys monitoring, evaluations, and disposition of issues in accordance with station
procedures and the requirements of 10 CFR 50.65, "Requirements for Monitoring the
Effectiveness of Maintenance." The inspectors reviewed the following documents
associated with the system design and licensing basis:
- Maintenance Rule Basis Document for Component Cooling Water, Revision 1
- System Health Report for the Component Cooling Water System, 4th quarter 2002
- Design Bases Document for the Component Cooling Water System, Revision 0
- System Engineering Procedure SE-303, Maintenance Rule Performance Criteria
Development/ Monitoring, Revision 0
- UFSAR Section 9.3, Auxiliary Cooling System
- Technical Specification 3.3.E, Component Cooling System
- Condition Report Nos. CR-IP2-2002-11242, CR-IP2-2003-00515, CR-IP2-2003-
01217
b. Findings
Enclosure
7
No findings of significance were identified.
.2 Boric Acid Transfer Pumps
a. Inspection Scope
The inspectors evaluated Entergys work practices and preventive maintenance activities
for the 21 and 22 boric acid transfer pumps (BATPs) to assess the effectiveness of
maintenance activities. The inspectors reviewed the performance history of the 21 and 22
BATPs to assess Entergys problem identification and the adequacy of the licensee's
corrective actions to evaluate whether monitoring, evaluations, and dispositioning of
issues were completed in accordance with station procedures and the requirements of
10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance." The
inspectors reviewed the following documents associated with system design and
licensing basis:
- Maintenance Rule Basis Document for the Chemical and Volume Control System
- System Health Report for the Chemical and Volume Control System, 4th quarter
2002
- Design Basis Document for the Component Cooling Water System, Revision 0
- System Engineering Procedure SE-303, Maintenance Rule Performance Criteria
Development/ Monitoring, Revision 0
- UFSAR Section 9.2, Chemical and Volume Control System
- Technical Specification 3.2, Chemical and Volume Control System
- Condition Report Nos. IP2-2003-01564, IP2-2003-01121, IP2-2003-00831, IP2-
2001-12846, IP2-2002-00441, and IP2-2002-02248
b. Findings
No findings of significance were identified.
Enclosure
8
1R13 Maintenance Risk Assessment and Emergent Work Activities
a. Inspection Scope
The inspector observed selected portions of emergent maintenance work activities to
assess the licensees risk management in accordance with 10 CFR 50.65 (a)(4). The
inspector verified that the licensee took the necessary steps to plan and control emergent
work activities, took actions to minimize the probability of initiating events, and
maintained the functional capability of mitigating systems. The inspector observed and
discussed risk management with maintenance and operations personnel for the following
activities:
- Surveillance test PT-Q55, during which pressurizer level bistable PC-457A failed
to trip (IP2-2003-00981)
rapidly increased to 2300 kW and then rapidly decreased to 0 kW (IP2-2003-
00570)
- 22 Battery Charger silicon-controlled rectifier replacement (IP2-2003-00732)
- Emergent maintenance to replace the 22 steam generator level bistable (IP2-
2003-00788)
b. Findings
.1 23 Emergency Diesel Generator Load Oscillations
Introduction: A Green Finding was identified for ineffective corrective actions that resulted
in repetitive surveillance test failures of the 23 emergency diesel generator, (non-cited
violation of 10 CFR 50 Appendix B, Criterion XVI).
Description: The inspector identified that during a period between May 28, 2000 and
February 6, 2003, the licensee did not adequately correct load oscillations during
surveillance testing on the 23 emergency diesel generator.
On January 29, 2003, the 23 emergency diesel generator (EDG) was started for its
quarterly surveillance. While the 23 EDG was incrementally being loaded past 500kW,
the load rapidly increased to 2300 kW. The nuclear plant operator attempted to lower
the load using the governor raise/lower switch which resulted in the load rapidly
decreasing to 0 kW and the EDG tripped on reverse power. This issue was documented
in CR-IP2-2003-00570 and required a root cause analysis. Troubleshooting identified
that the motor operated potentiometer (MOP) may have had a dead spot, which could
explain why the 23 EDG load oscillations were intermittent. The MOP was replaced and
the 23 EDG was declared operable. Since failure analysis on the MOP would take
several weeks, the licensee increased the surveillance frequency on the 23 EDG to
provide confidence that the EDG was operable. On February 6, 2003, the 23 EDG again
experienced load oscillations during the surveillance testing.
Enclosure
9
Following the January 29, 2003 load oscillations, the inspectors reviewed the past work
orders (WOs) and condition reports (CRs) associated with the 23 EDG and identified
several CRs and WOs documenting load oscillations between May 2000 and
February 2003. The work orders documenting load issues associated with the 23 EDG
were:
- May 28, 2000, (IP2-2000-03978) 23 EDG increased rapidly from about 750 kW
and stayed at 2300 kW for about one minute. The EDG was manually unloaded
and tripped on reverse power. Corrective maintenance involved replacement of
the unit parallel relay; additionally, contact resistance on the unit/parallel switch
was checked.
- December 13, 2001, (IP2-2001-12264) surveillance test PT-M21C on 23 EDG
was aborted due to load swings with the governor. Corrective maintenance
involved the removal and replacement of the motor operated potentiometer
(MOP).
- March 23, 2002, (IP2-2002-03079) the MOP for the 23 EDG would not increase
or lower generator voltage, the EGB governor was replaced.
- October 8, 2002, (IP2-2002-09072) the operator tripped the 23 EDG during PT-M-
21C surveillance test due to unexpected response of the governor load control,
the EGA governor was replaced.
- January 29, 2003, (IP2-2003-00570) the load on the 23 EDG increased
uncontrollably to 2300 kw and then decreased to 0 kW. Corrective maintenance
involved replacement of the motor operated potentiometer.
- February 6, 2003, (IP2-200300758) load oscillations were observed on the 23
EDG and the licensee replaced the unit parallel relay and associated cables.
The review of the work history between May 2000 and February 2003 highlighted that the
major components that could cause the load swings were replaced at least once and, in
the case of the motor operated potentiometer, three times. In response to previous
condition reports, the licensee used industry operating experience to determine the most
probable cause of the load swings and justified continued EDG operation. The inspector
concluded that the responses to these condition reports did not include an evaluation of
the 23 EDG operating history. Condition Report IP2-2003-00570 required a full root
cause which included listing all the potential causes along with the past condition reports
and work history. This root cause was thorough and logical, and although no specific
cause of the load oscillations was determined, it provided confidence that the complete
spectrum of possibilities and the complete history were considered.
Analysis: The failure to correct the multiple generator load oscillations was more than
minor because the surveillance test failures associated with the load oscillations
impacted the availability of mitigating equipment. The inspectors also determined that
this finding was able to be assessed using the Significance Determination Process
because the finding was associated with the availability of a system or train in a
mitigating system. The inspectors conducted a Phase 1 Significance Determination
Process screening and determined that the failure to adequately address the cause of
multiple surveillance test failures of the 23 EDG due to load oscillations was of very low
risk significance because this finding did not represent an actual loss of safety function.
Enclosure
10
The inspectors confirmed that the last two surveillances that demonstrated automatic
start and loading of the 23 emergency diesel generator during accident conditions did not
result in load oscillations.
Enforcement: Criterion XVI of 10 CFR Part 50, Appendix B requires that in the case of
significant conditions adverse to quality, that measures shall assure that the cause of the
condition is determined and corrective actions taken to preclude repetition. The
licensees failure to adequately correct the load oscillations associated with the 23
emergency diesel generator between May 2000 and February 2003 was considered a
non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI in accordance with
Section VI.A.1 of the NRCs Enforcement Policy (NCV 50-247/03-03-02). This issue was
entered into the licensees corrective action program as IP2-2003-00570.
.2 Maintenance Instruction Deficiency
Introduction: A Green NCV was identified for inadequate emergent maintenance
instructions that subsequently resulted in operator action to restore pressurizer level and
pressure based upon de-energized control channel instruments.
Description: On February 7, 2003, inadequate emergent work instructions in work order
03-12284 resulted in an electrical short during replacement of the 22 steam generator
low level bistable. The electrical short caused the trip of circuit 10 on instrument bus 21.
Operators were subsequently challenged to restore pressurizer level and reactor coolant
system pressure due to the controlling channels failing low, based upon a loss of the
instruments 120 volt power source. Specifically, prior to operator actions to shift control
channels, reactor coolant system pressure decreased approximately 60 psig (resulting in
entry into TS 3.1.G.b) and pressurizer level increased 3% above the program band.
Analysis: This performance issue is more than minor since the operators were required
to take action to restore reactor coolant system pressure and pressurizer level to
preclude a reactor trip. The performance issue involved the initiating events cornerstone
in that it increased the likelihood of upset in plant stability; the attribute was human error
during the planning of an emergent work activity. In accordance with NRC Manual
Chapter 0609, Appendix A, this finding is considered to be of very low safety significance.
This conclusion is based upon the finding not contributing to the likelihood of a secondary
or primary LOCA initiator and not contributing to either a reactor trip or to mitigation
system unavailability.
Enforcement: The inadequate emergent maintenance instruction is a violation of 10 CFR
50 Appendix B, Criterion V, in that the instructions were not appropriate to the
circumstances. Specifically, on February 7, 2003, the instructions for work order 03-
12284 did not include information to minimize the likelihood of an electrical short near
energized reactor protection system bistables and did not have maintenance work
prerequisites to minimize plant transient impact, if the affected circuit were to be
inadvertently de-energized. The performance issue was considered a non-cited violation
of 10 CFR 50 Appendix B, Criterion V in accordance with Section VI.A.1 of NRCs
Enclosure
11
Enforcement Policy (NCV 50-247/03-03-03), and was documented in Entergys corrective
action program under CR No. IP2-2003-00788. Short-term corrective actions included
lessons-learned with both operations and instrument & control department personnel,
work planners review of the apparent cause report for IP2-2003-00788, and development
of a procedure to replace reactor protection system bistables.
1R14 Personnel Performance During Non-Routine Plant Evolutions and Events
.1 Heater Drain Pumps Tripping due to Leak Repair on the Heater Drain Tank Level
Column
a. Inspection Scope
On January 9, 2003, both heater drain tank pumps tripped causing the reactor operators
to decrease reactor power from 100% to 80% to maintain steam generator level. Prior to
the heater drain tank pumps tripping, a steam leak repair had just been completed on the
heater drain tank level transmitter (LT-1127). The inspectors observed operator
response, reviewed operator logs, interviewed cognizant personnel, and reviewed the
licensees root cause analysis report.
b. Findings
No findings of significance were identified.
.2 22 Main Condensate Pump Motor Failure
a. Inspection Scope
On March 3, 2003, at 8:42 p.m. the control room received a call from the on-shift
chemistry technician that the 22 condensate pump motor was on fire. The control room
sounded the fire alarm and dispatched the fire brigade. The fire was extinguished four
minutes later. Operators entered into AOI 21.1.1, Loss of Feedwater, and reduced
reactor power to 90 percent. Operators had to restore a number of non-safety related
pumps and fans in response to a voltage perturbation on the 6.9 KV bus which resulted
from a phase-to-phase fault within the 22 condensate motor. This event was
documented in Condition Report IP2-2003-1264.
The inspector reviewed the following documents in response to this plant transient:
- Condensate motor maintenance work history and corrective action program
history
- Protective relay test results for the 22 condensate motor breaker
- AOI 21.1.1, Loss of Feedwater
- Emergency Action Levels
The inspector evaluated equipment response, operator response to the transient, fire
brigade response, and short-term corrective actions taken by Entergy. The cause of the
Enclosure
12
motor failure was a phase-to-phase power supply cable fault. The fire was confined to
the cable insulation within the splice box where the fault originated.
b. Findings
No findings of significance were identified.
.3 Loss of Control Power to 22 Main Transformer Auxiliaries
a. Inspection Scope
On March 19, 2003, operators responded to a loss of control power to the 22 main
transformer auxiliaries. The cause of the loss of control power was a failure of the 480
volt/120 volt transformer. Operators entered into AOI 27.1.7 and reduced thermal power
to 78 percent. Transformer oil temperature reached 109 degrees centigrade (one degree
from a required turbine trip per AOI 27.1.7) before the operators installed a mechanical
blocking device on the auxiliary contactors and re-energized the transformer auxiliaries.
Transformer oil temperatures decreased to normal values after auxiliaries were restored.
The inspectors evaluated operator response to this event, reviewed the adequacy of AOI
27.1.7 guidance for coping with this transient, and verified short-term corrective action
involving the temporary alteration/blocking device (see report detail 1R23). Entergy
documented the following condition reports involving the loss of control power: IP2-2003-
1635; IP2-2003-1638; IP2-2003-1640; IP2-2003-1652; and IP2-2003-1673.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the below listed Condition Reports (CRs) and associated
operability evaluations to ensure that operability was properly justified and that the
component or system remained available without a significant degradation in
performance or unrecognized operability issue. The inspectors used Technical
Specifications, Updated Final Safety Analysis Report, and design basis documents, as
appropriate.
- IP2-2003-01202, No. 21 accumulator gas and fluid piping ISI inspections.
- IP2-2003-00857, 480V breaker No. 2053-002.
- IP2-2003-00938, 480V breaker for No. 22 BATP motor disconnect at MCC No.
27.
- IP2-2003-00992, EDG building HVAC damper air supply pressure regulating
valve PRV-5469.
Enclosure
13
- IP2-2003-01211, No. 21 EDG miscellaneous mounting bolts and brackets not fully
secured.
- IP2-2003-01406, EDG fuel oil day tank drain valve leakage.
- IP2-2003-01517 and IP2-2000-09073, Impulse line tubing for the containment
pressure transmitters 1814B and 1814C are bent.
b. Findings
No findings of significance were identified.
1R17 Permanent Modifications
Station Auxiliary Transformer Load Tap Changer Modification
a. Inspection Scope
The licensee recently completed two preliminary calculations, FEX-00143-01, IP2 Load
Flow Analysis of the Electrical Distribution System, and FEX-00181-00, Evaluation of
the Load Tap Changer Operation of the Station Auxiliary Transformer Following Fast-
Transfer. These preliminary calculations showed that under certain expected grid
voltage conditions, coincident with a plant event which required safety injection (SI), the
safety buses at the plant could separate from the off-site power supplies. During normal
plant operation, four of the 6.9 kV buses are supplied by the unit auxiliary transformer
(UAT). With a unit generator trip (30 seconds after the SI initiation), the supply for these
four buses would be fast-transferred to the station auxiliary transformer (SAT). The SAT
has an automatic load tap changer (LTC) which maintains the secondary voltage at 7.1
kV. With the existing LTC operation, the fast transfer could cause the secondary voltage
to drop below the degraded voltage setpoint for more than 10 seconds, resulting in a
separation of the safety buses from the off-site power. This issue was documented in
CR 2002-07918, dated August 21, 2002. The licensee found that the design basis
calculation (EGP-001100-00) which evaluated compliance with degraded grid
requirements and compliance with 10 CFR 50, Appendix A, General Design Criteria 17,
had a number of non-conservative assumptions. For example, the calculation did not
account for: the fast bus transfer 30 seconds after a safety injection signal, instrument
tolerances for the degraded voltage relays, and the neutral position of the LTC.
The licensee initiated design change package (DCP) 02-2-005, SAT Load Tap Changer
SI Modification, to improve the SAT secondary voltage response following an SI
initiation. The design of this modification was completed on October 3, 2002, and the
modification was to be implemented during the November 2002 outage. The
modification involved the addition of a bypass circuit (for a duration of 40 seconds only) in
the LTC control circuitry that is activated by the SI signal. The purpose of the
modification was to quickly raise, following the two second time delay of the LTC and
within the time limit of 40 seconds, the SAT secondary voltage to a maximum of 7350 V
or to the highest step of the LTC before the fast-transfer takes place (30 seconds after SI
initiation). At the time of the inspection (week of November 4, 2002), the relay box of the
Enclosure
14
bypass circuit was installed, field wiring was in-progress, and the pre-installation
calibrations of the voltage sensing and time delay relays were completed.
The inspector selected DCP 02-2-005 for review because preventing a degraded voltage
condition at the safety-related buses contributes significantly to the prevention of core
damage. The inspector reviewed the design features (including voltage settings and time
delay settings of the voltage sensing and time delay relays) to verify that the design
requirements were met. The inspector also reviewed the modified schematic diagrams,
with the added bypass circuit to the LTC control circuitry, to verify the adequacy of the
new design. In addition, the inspector reviewed the bench and functional testing
requirements and verified that appropriate acceptance criteria were specified.
b. Findings
At the end of the inspection period, Entergy was in the process of completing the
reconstitution of the electrical calculations to support the degraded grid analysis. Entergy
has open corrective action assignments to evaluate the implications on past operability of
the system and to evaluate reportability per 10 CFR 50.73. The inspector considers this
issue unresolved, pending NRC review of the final electrical calculations and implications
on historical plant risk of off-site power source reliability. (URI 50-247/03-03-04)
1R19 Post Maintenance Testing
a. Inspection Scope
The inspector reviewed post-work test (PWT) procedures and associated testing
activities to assess whether: 1) the effect of testing in the plant had been adequately
addressed by control room personnel; 2) testing was adequate for the maintenance work
order (WO) performed; 3) acceptance criteria were clear and adequately demonstrated
operational readiness consistent with design and licensing documents; 4) test
instrumentation had current calibrations, range, and accuracy for the application; and 5)
test equipment was removed following testing.
The selected testing activities involved components that were risk significant as identified
in IP2s Individual Plant Examination. The regulatory references for the inspection
included Technical Specification 6.8.1.a. and 10 CFR 50, Appendix B, Criteria XIV,
Inspection, Test, and Operating Status. The following testing activities were evaluated:
- WO IP2-03-10372 and IP2-02-3307, PWT to verify 22 service water pump
strainer functions properly, performed on January 21, 2003.
- WO IP2-03-10335 and IP2-03-010189, PWT using PT-Q34 for 22 auxiliary
feedwater pump, performed on January 10, 2003.
- CR-IP2-2003-01121, boric acid flow was not verified during blended makeup on
February 26, 2003, and WO-IP2-00-13327, preventive maintenance on the boric
acid transfer pump 22 outlet to boric acid filter stop, performed in March 2001.
Enclosure
15
- WOs IP2-03-14057 and IP2-02-33275, PWT using PT-M38A for gas turbine No. 1
and IP2-03-04664, black start diesel tripped on high cooling water temperature
during PT-M38A, performed on March 21 and 22, 2003.
- WO IP2-03-15081, PWT to verify functionality after replacing oil in the B stator
water cooling pump, performed on March 25, 2003.
- WO IP2-03-10989, PWT following replacement of silicon controlled rectifier on
the 22 battery charger (CR 2003-00732), performed on February 4, 2003.
b. Findings
Introduction: A Green NCV was identified for an inadequate post-maintenance test on the
22 boric acid transfer pump outlet to the boric acid filter stop (valve No. 370) in 2001.
Description: A self-revealing event was identified on February 26, 2003, when operators
observed no boric acid flow to the reactor core via the 22 boric acid transfer pump
(BATP) using blended makeup. During preventive maintenance activities in March 2001,
the post-work test on valve No. 370 failed to identify that an internal plate to the valves
diaphragm was installed upside down. The consequence of the finger plate installed
upside down resulted in the diaphragm being cut and subsequently causing the valve to
hydraulically lock. This degraded valve condition was not identified during surveillance
testing because flow does not pass through the valve during periodic testing.
Analysis: The performance deficiency is considered more than minor because the
improperly installed valve plate was not identified during the post work test and adversely
impacted the availability of a single train of emergency boration. This finding is
considered to be of very low risk significance in accordance with NRC MC 0609
Appendix A, since the emergency boration safety function was not lost due to this
performance issue.
Enforcement: This finding is a violation of 10 CFR 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings, in that the post-work test prescribed in work
order No. IP2-00-13327 did not adequately verify that the valve was properly reinstalled
after preventive maintenance. The performance issue was considered a non-cited
violation of 10 CFR 50 Appendix B, Criterion V in accordance with Section VI.A.1 of
NRCs Enforcement Policy (NCV 50-247/03-03-05), and was documented in Entergys
corrective action program under CR No. IP2-2003-01121.
Enclosure
16
1R22 Surveillance Testing
a. Inspection Scope
The inspector reviewed surveillance test procedures and observed testing activities to
assess whether: 1) the test preconditioned the component tested; 2) the effect of the
testing was adequately addressed in the control room; 3) the acceptance criteria
demonstrated operational readiness consistent with design calculations and licensing
documents; 4) the test equipment range and accuracy was adequate and the equipment
was properly calibrated; 5) the test was performed per the procedure; 6) the test
equipment was removed following testing; and 7) test discrepancies were appropriately
evaluated. The surveillance tests observed were based upon risk significant components
as identified in the Indian Point 2 Individual Plant Examination. The regulatory
requirements that provided the acceptance criteria for this review were 10 CFR 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, Criterion XIV,
Inspection, Test, and Operating Status, Criterion XI, Test Control, and Technical
Specifications 6.8.1.a. The following test activities were reviewed:
- PT-Q48, AMSAC Logic, revision 5, performed on January 22, 2003
- PT-M21A, Emergency Diesel Generator 21 Load Test, revision 7, performed on
January 30, 2003
- SOP 1.7, Reactor Coolant System Leakage Surveillance, revision 35 N-1,
performed on February 12, 2003
- PT-Q35B, No. 22 Containment Spray Pump Test, revision 12, performed on
March 11, 2003
- PT-Q29C, 23 Safety Injection Pump, revision 13, performed on February 21,
2003.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope (71111.23)
The inspector reviewed the below listed temporary alteration (TA) to ensure that: the TA
was appropriately evaluated by Entergy in accordance with 10 CFR 50.59; the TA did not
adversely impact the safety function or operation of the system/component modified; and
that the TA was appropriately installed in accordance with administrative procedure ENN-
DC-136, Temporary Alteration Control. One minor drawing issue was identified by the
inspector and entered into the licensees corrective action process for resolution. The
following TA was reviewed:
- TA-03-2-089, Temporary power to 22 main transformer auxiliary panel.
b. Findings
Enclosure
17
No findings of significance were identified.
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
During a combined in-office and on-site inspection during January 6 - 29, 2003, the
inspectors reviewed recent changes in the EP area. Specifically, Unit 2 and Unit 3
emergency plans were combined into a common Emergency Plan. Also, certain
implementing procedures for the Emergency Operation Facility and the Joint News
Center are now common to both units. A thorough review was conducted of aspects of
the plan related to the risk significant planning standards (RSPS), such as classifications,
notifications, and protective action recommendations. A general review was conducted
for non-RSPS portions. These changes were reviewed against 10 CFR 50.54(q) to
ensure that the changes did not decrease the effectiveness of the plan, and that the
changes continued to meet the standards of 10 CFR 50.47(b) and the requirements of
Appendix E. For areas for which minor clarifications would enhance the new Emergency
Plan, the licensee generated CRs. All of the changes made to the Emergency Plan or
associated implementing procedures are subject to future inspections to ensure that the
result of the changes continue to meet NRC regulations.
b. Findings
No findings of significance were identified.
1EP6 Emergency Plan Drills
a. Inspection Scope
On February 26, 2003, the inspectors observed Entergys emergency response
organization during an announced emergency preparedness training drill at Indian Point
Unit 2. The simulated emergency included the activation of the Operations Support
Center (OSC), the Technical Support Center (TSC) and Emergency Operations Facility
(EOF) after an Alert (simulated) was declared by the control room operators. The control
room simulator was used for the exercise, in addition to the OSC, TSC, EOF, and the
Joint News Center (JNC).
The inspectors observed the conduct of the exercise in the control room simulator, OSC,
TSC, and EOF. The inspectors assessed licensed operator and the licensees adherence
to emergency plan implementation procedures, and their response to simulated
degraded plant conditions to identify weaknesses and deficiencies in classification,
notification, and protective action recommendation activities. In addition to the drill, the
inspectors observed the licensees controller critique to evaluate the licensees self-
identification of weaknesses and deficiencies. The inspectors compared the licensees
identified findings against their observations. The inspectors' review included the
following documents and procedures:
Enclosure
18
- Indian Point Energy Center Emergency Plan, revision 03-01
- Implementing Procedure (IP)-1002, Emergency Notification and Communication
- IP-1010, Central Control Room
- IP-1023, Operations Support Center
- IP-1030, Emergency Operations Facility
- Technical Support Center Drill Log
- Operation Support Center Drill Log
- Condition Report Nos. IP2-2003-01346, IP2-2003-01145, IP3-2003-00937, IP2-
2003-01350, IP2-2003-01349, and IP2-2003-01347
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety (OS) and Public Safety (PS)
2OS1 Access Control to Radiologically Significant Areas
a. Inspection Scope
The inspector reviewed radiological work activities and practices and procedural
implementation during tours and observations of the facilities. Additionally, the inspector
reviewed procedures, records, and other program documents to evaluate the
effectiveness of access controls to radiologically significant areas. Further, the inspector
observed activities at the routine radiologically-controlled-area (RCA) access control point
(HP-1) on several occasions to verify compliance with requirements for RCA entry and
exit, dosimetry placement, and issuance and use of electronic dosimeters.
On February 24, 2003, the inspector discussed the status of the radiation protection
organization and procedures for Units 2 and 3 with the radiation protection manager
(RPM). The inspector also discussed the radiological work activities and dose
projections for the upcoming week for each unit.
On February 25, 2003, the inspector reviewed the radiation work permit (No. 032028)
used for non-outage containment entries at Unit 2. Also, the inspector discussed with the
RPM the methods for the segregation of high level and low level dry active radioactive
waste in work areas during outages with radioactive waste personnel and radiation
protection technicians from both units. In addition, the inspector discussed survey
frequencies and posting and their use for briefings of radiation workers with a Unit 2
radiation protection supervisor.
On February 26, 2003, the inspector toured and observed work activities in selected
portions of the fuel handling building and the chemical systems building in Unit 1,
including the area in the sphere annulus area where the pipe from the north curtain drain
Enclosure
19
was located. Also, the inspector toured and observed work activities in various
elevations in the primary auxiliary building in Unit 2. During these tours and
observations, the inspector reviewed, for regulatory compliance, the performance of the
radiation workers and radiation protection technicians and the posting, labeling,
barricading, and level of radiological access control for locked high radiation areas
(LHRAs), high radiation areas (HRAs), radiation and contamination areas, and
radioactive material areas. The inspector reviewed and observed work activities for
compliance with the radiation work permit (RWP) requirements.
The inspector performed a selective examination of procedures, records, and other
program documents (reference the List of Documents Reviewed Attachment) to evaluate
the adequacy of radiological controls. This review was against criteria contained in 10
CFR 19.12, 10 CFR 20 (Subparts D, F, G, H, I, and J), Technical Specifications, and site
procedures.
b. Findings
No findings of significance were identified.
2OS2 ALARA Planning and Controls
a. Inspection Scope
The inspector reviewed the effectiveness of Entergys program to maintain occupational
radiation exposure as low as is reasonably achievable (ALARA).
On February 24, 2003, the inspector discussed the Unit 2 and 3 cumulative dose results
for 2002, and the cumulative dose estimates for 2003, with the technical support
manager. Further, the inspector discussed the integration of the ALARA planning
process into the stations work planning and control process with an ALARA radiological
engineer.
On February 26, 2003, the inspector examined the pre-job ALARA review for 2R15 RWP
No. 025226, involving outage valve work and the in-progress and post-job ALARA
reviews for the same job, to assess the effectiveness of the radiological controls. The
inspector also reviewed the post-job ALARA review for 2R15 RWP No. 025206, involving
outage radiological waste support.
The inspector performed a selective examination of procedures, records, and documents
(reference the List of Documents Reviewed Attachment) for regulatory compliance and
for adequacy of control of radiation exposure. This review was against criteria contained
in 10 CFR 20.1101 (Radiation protection programs), 10 CFR 20.1701 (Use of process or
other engineering controls), and site procedures.
b. Findings
No findings of significance were identified.
Enclosure
20
2OS3 Radiation Monitoring Instrumentation and Protective Equipment
a. Inspection Scope
The inspector reviewed the program for health physics instrumentation to determine the
accuracy and operability of the instrumentation.
During the plant tour on February 26, 2003, described in Section 2OS1 of this report, the
inspector reviewed field instrumentation utilized by health physics technicians and plant
workers to measure radioactivity and radiation levels including: portable field survey
instruments; hand-held contamination frisking instruments; continuous air monitors;
installed radiation monitors; whole body friskers; portal monitors; area monitors, and
process monitors. The inspector conducted a review of the instruments observed in the
toured areas, specifically for verification of current calibrations, appropriate source
checks, and proper function.
The inspector performed a selective examination of documents (reference the List of
Documents Reviewed Attachment) for regulatory compliance and adequacy. This review
was against criteria contained in 10 CFR 20.1501, 10 CFR 20 Subpart H, Technical
Specifications, and site procedures.
b. Findings
No findings of significance were identified.
2PS1 Gaseous and Liquid Effluents
a. Inspection Scope
The inspector reviewed the following documents to evaluate the effectiveness of the
licensees radioactive gaseous and liquid effluent control programs. The requirements
for radioactive effluent controls are specified in the Technical Specifications and the
Offsite Dose Calculation Manual (TS/ODCM):
- the 2001 Radiological Annual Effluent Release Report, including projected public
dose assessments;
- review of the current ODCM (Revision 6, October 28, 1999), including technical
justifications for Revision 7;
- selected 2002 analytical results for charcoal cartridge, particulate filter, and noble
gas samples;
- implementation of the compensatory sampling and analysis program when the
effluent radiation monitoring system (RMS) was out of service;
- implementation of IE Bulletin 80-10;
- selected 2002 radioactive liquid and gaseous release permits;
- associated effluent control procedures, including analytical laboratory procedures;
- calibration results for chemistry laboratory measurement equipment (gamma and
liquid scintillation counters);
Enclosure
21
- implementation of the measurement laboratory quality control program, including
effluent intra-laboratory and inter-laboratory comparisons and control charts;
- the 2001 and 2002 NQA Audits (Audit Nos. 01-AR-21-RP, August 1-8, 2001 and
02-AR-14-RP, April 11-17, 2002) of the implementation of the radioactive liquid
and gaseous effluent control program and the ODCM;
- Radiation Monitoring System Reliability Plan;
- the most recent Channel Calibration and Channel Functional Test results for the
radioactive liquid and gaseous effluent radiation monitoring system (RMS) and its
flow measurement devices as listed in Tables 4.10-2 and 4.10-4 of the Technical
Specifications (TS):
Unit 1 RMS:
6 Service/River Water Liquid Radiation Monitor (R-51);
6 Liquid Discharge Radiation Monitor (R-54);
6 Secondary Boiler Blowdown Effluent Line (R-52);
6 Sphere Foundation Sump Discharge Monitor (R-62); and
6 Stack Vent Noble Gas Monitor (R-60).
Unit 2 RMS:
6 Waste Disposal Liquid Effluent Line (R-48);
6 Component Cooling Water Radiation Monitor (R-47);
6 Steam Generator Blowdown Effluent Line (R-49);
6 Service Water System Effluent Line Monitors (R-46/53);
6 Component Cooling Service Water Heat Exchangers (R-39/40);
6 Plant Vent Noble Gas Monitors (R-44 and R-27); and
6 Large Gas Decay Holding Tank Monitor (R-50).
Enclosure
22
Units 1 & 2 Flow Rate Measurement Devices:
6 Stack Vent Flow Rate Monitor;
6 Plant Vent Flow Rate Monitor;
6 Liquid Effluent Line Flow Rate Monitor; and
6 Steam Generator Blowdown Effluent Line.
- the most recent surveillance testing results for the following air treatment systems
listed in the following TS:
6 TS 4.5.D Containment Fan Cooler System (air flow tests for five Fan
Cooler Units);
6 TS 4.5.E Control Room Air Filtration System (system flow rate,
laboratory test in accordance with ASTM D3803-1989, in-
place testings for HEPA and charcoal filters, pressure drop
test, visual inspection);
6 TS 4.5.F Fuel Storage Building Air Filtration System (system flow
rate, laboratory test in accordance with ASTM D3803-1989,
in-place testings for HEPA and charcoal filters, pressure
drop test, visual inspection); and
6 TS 4.5.G Post-Accident Containment Venting System (system flow
rate, laboratory test in accordance with ASTM D3803-1989,
in-place testings for HEPA and charcoal filters, pressure
drop test, visual inspection).
The inspector also toured and observed the following activities to evaluate the
effectiveness of the licensees radioactive gaseous and liquid effluent control programs:
- availability of radioactive liquid/gaseous effluent RMS to determine the equipment
material condition; and
- operability of air cleaning systems to determine the equipment material condition.
b. Findings
No findings of significance were identified.
2PS2 Radioactive Material Processing and Transportation
a. Inspection Scope
The inspection consisted of a review of Condition Report IP2-2003-00771, identified in
the Corrective Action Program (CAP), for the appropriateness and adequacy of event
categorization, immediate corrective action, corrective action to prevent recurrence, and
timeliness of corrective action.
b. Findings
Enclosure
23
Introduction. A Green self-revealing non-cited violation (NCV) of 10 CFR 71.12, which
addresses general licenses for NRC-approved packages, was identified for failure to
comply with the package procedures relating to the use and maintenance of the
packaging.
Description. Condition Report IP2-2003-00771 (dated February 6, 2003), documented
that a shipment of filters, packaged in a CNS 8-120 B cask (an NRC-approved Type B
shipping container), left Indian Point 2 on February 3, 2003, and arrived at a
consolidation facility in South Carolina on February 5, 2003. During the unloading
process, facility personnel discovered that a bolt, that was to be installed in the primary
lids air pressure test port, in accordance with procedure TR-OP-035, Handling
Procedure for CNS 8-120 B, was missing. The bolt had not been installed during the re-
assembly of the cask for shipment.
Analysis. This finding constituted a performance deficiency in that it resulted in a
requirement not being met that was reasonably within Entergys ability to foresee and
correct and that should have been prevented. This finding was more than minor in that
the finding was associated with the Public Radiation Safety Cornerstones attribute of
procedures for transportation packages. The finding affected the associated cornerstone
objective to ensure adequate protection of public health and safety from exposure to
radioactive materials released into the public domain. Specifically, a
procedure/document, relating to the preparation, use, and maintenance of an NRC-
approved Type B packaging was not properly implemented, and the package was
shipped on a public highway. Following the Public Safety Significance Determination
Process, the issue was determined to be of very low safety significance in that the finding
did not involve exceeding transportation radiation limits, there was no breach of the
package during transit, and it was a Certificate of Compliance (CoC) maintenance/use
performance deficiency.
Enforcement. 10 CFR 71.12(a) and (c), together with paragraphs 9(i) and 9(iii) of the
NRC Certificate of Compliance No. 9168 and procedure TR-OP-035, Handling
Procedure for CNS 8-120 B, require that a bolt shall be installed and torqued into place
in the primary lids air pressure test port prior to shipment. Contrary to these
requirements, on February 3, 2003, a bolt was not installed and torqued into place in the
primary lids air pressure test port prior to shipment.
Entergy actions associated with this finding are documented CR IP2-2003-00771.
Because this self-revealing violation was of very low safety significance and because
Entergy entered these issues into its corrective action program, this violation is being
treated as a self-revealing NCV, consistent with Section VI.A of the NRC Enforcement
Policy. (NCV 50-247/03-03-06)
Enclosure
24
4. OTHER ACTIVITIES (OA)
4OA1 Performance Indicator Verification
The inspector reviewed the licensees performance indicator (PI) data collecting and
reporting process as described in procedure SAO-114, Preparation of NRC and WANO
Performance Indicators. The purpose of the review was to determine whether the
methods for reporting PI data are consistent with the guidance contained in Nuclear
Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator
Guidelines, Revisions 1 and 2. The inspection included a review of the indicator
definitions, data reporting elements, calculation methods, definition of terms, and
clarifying notes for the performance indicators. Plant records and data were sampled
and compared to the reported data. The inspector reviewed the licensees actions to
address and satisfactorily resolve discrepancies in the performance indicator data.
.1 Reactor Coolant System Leakage
a. Inspection Scope
The inspector reviewed the performance indicator (PI) for reactor coolant system (RCS)
leakage for the period from January - December 2002. This PI remained in the Green
band. The inspector reviewed the completed SOP 1.7 RCS leak rate surveillance
determinations to verify the adequacy of the reported PI data. The inspector observed
licensee performance of the leak rate surveillance on February 12, 2002. The licensees
corrective action program records were also reviewed to determine if any problems with
the collection of PI RCS leakage data had occurred. The inspectors compared the PI
data against the guidance contained in NEI 99-02.
b. Findings
No findings of significance were identified.
.2 Scrams Per 7,000 Critical Hours
a. Inspection Scope
The inspector reviewed Entergys PI data for Unplanned Scrams Per 7,000 Critical Hours
to verify whether the PI data was accurate and complete. The PI remained in the green
band for the four quarters of 2002. The inspector reviewed operator logs, licensee event
reports, and monthly operating reports to compare PI data reported by the licensee. The
inspectors compared the PI data against the guidance contained in NEI 99-02.
b. Findings
No findings of significance were identified.
.3 Residual Heat Removal System Unavailability
Enclosure
25
a. Inspection Scope
The inspector reviewed Entergys Performance Indicator (PI) data for Residual Heat
Removal (RHR) Safety System Unavailability to verify whether the PI data was accurate
and complete. The inspectors compared the PI data reported by the licensee to
information gathered from the control room logs, condition reports, and work orders for
the four quarters of 2002. In addition, the inspectors interviewed the system engineers.
The inspectors compared the PI data against the guidance contained in NEI 99-02.
b. Findings
No findings of significance were identified.
.4 Emergency AC Power System Unavailability
a. Inspection Scope
The inspector performed a review of the 2002 quarterly performance indicator data
submitted by the licensee for the safety system unavailability of the emergency AC power
system (emergency diesel generators) to determine its accuracy and completeness. The
inspector researched the control room operating logs and the condition reporting system
to identify when the emergency diesel generators were out of service during the period of
review. The control room operating logs were also reviewed to determine the number of
hours the EDGs were required to be operational. The inspector used the guidance
provided in NEI Report 99-02 to calculate the ratio of the number of hours the emergency
AC power system was unavailable to the number of hours the emergency AC power
system was required.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1 Baseline Procedure Problem Identification and Resolution Review
a. Inspection Scope
The inspection included a review of the following issues identified in the corrective action
program for the appropriateness and adequacy of event categorization, immediate
corrective action, corrective action to prevent recurrence, and timeliness of corrective
action: Condition Report Nos. IP2-2002-10106 and -10795 and 2003-00328, -00400, -
00401, -00751, -00771, -00826, 2001-09250, 2001-09604, 2001-12738, 2001-11035,
2001-02811, 2001-11958, 2001-11056, 2002-11130, 2001-07475, 2001-11614, 2002-
01208, 2002-02184, 2002-08402, 2002-11130, 2001-09250, 2001-09604, 2001-12738,
2001-11035, 2001-02811, 2001-11958, 2001-11056, 2002-11130, 2001-07475, 2001-
11614, 2002-01208, 2002-02184, 2002-08402, 2002-00504, 2002-03729,2002-
Enclosure
26
03245,2002-10605, 2002-05578, 2002-50779, 2002-04353, 2002-05578, 2002-07617,
2002-10071, and 2002-10605
b. Findings
No findings of significance were identified.
.2 Adverse Trend in Residual Heat Removal Boron Concentration, IP2-2002-03035
a. Inspection Scope
The inspector selected CR No. IP2-2002-03035 for detailed review. The condition report
was associated with an adverse trend (decreasing) in residual heat removal (RHR) boron
concentration. The CR was reviewed to ensure a complete and accurate identification of
the issue, an appropriate evaluation was performed, and appropriate corrective actions
were specified and prioritized. The inspector evaluated the report against the
requirements of the licensees corrective action process (CAP) as delineated in Site
Administrative Procedure ENN-LI-1102, Revision 2, Corrective Action Process.
b. Findings
There were no findings associated with the sample CR reviewed; however, the inspector
found that the licensee had not confirmed that the adverse trend was corrected. The
licensee performed an apparent cause evaluation and concluded that the most likely
source of the leakage into the RHR system and resulting boron dilution was occurring
through valves 730 and 731. The apparent cause evaluation was performed through a
review of past valve leakage history in the RHR system. Based on this determination,
preventive and corrective maintenance was performed on these valves and the CR was
closed. The sample for boron analysis is taken from the system when the RHR pumps
are run during their scheduled surveillance test to assure thorough mixing of the water
within the system. The inspector determined that the adequacy of the apparent cause
determination and the success of corrective actions cannot be confirmed until
subsequent quarterly pump testing is completed. Since the apparent cause evaluation
appeared to be reasonable and the corrective actions were timely, relative to the
significance of the condition, no violation of regulatory requirements was identified.
Enclosure
27
.3 Loss of Security Perimeter Lighting, IP2-2002-11628 and 2002-11629
a. Inspection Scope
The inspector selected CR Nos. IP2-2002-11628 and -11629 for a detailed review. The
CRs were associated with a loss of perimeter lighting on December 27, 2002. The
inspector observed that Entergys short-term compensatory actions were consistent with
the Security Contingency Plan, observed short-term corrective actions to repair and
restore the lighting, and confirmed long-term work orders existed to improve the reliability
and material condition of the perimeter lighting.
b. Findings
No findings of significance were identified.
.4 Communication failures between the Emergency Operations Facility computer system
and the field sirens, IP2-2003-01107
a. Inspection Scope
The inspectors selected CR No. IP2-2003-01107 for detailed review. The CR was
associated with communication failures between the emergency operations facility (EOF)
computer system and the field sirens that alert and notify the public in case of an event at
Indian Point. The report was reviewed to ensure that the full extent of the issue was
identified, an appropriate evaluation was performed, and that appropriate corrective
actions were specified and prioritized. The inspectors evaluated this CR against the
requirements of 10 CFR 50.47, Emergency Plans, and Appendix E, Emergency
Planning and Preparedness for Production and Utilization Facilities.
b. Findings
No findings of significance were identified.
.5 Fundamental Improvement Plan Effectiveness Reviews
a. Background and Scope
In January 2002, Entergy provided the NRC with a copy of the fundamental improvement
plan (FIP) consistent with the NRCs action matrix for a multiple degraded cornerstone
facility. The fundamental improvement plan documented corrective action plans and
effectiveness reviews associated with five key areas involving human performance,
design control/licensing basis, equipment performance/work management, problem
identification and resolution, and licensed operator performance. By letter dated
August 28, 2002, the NRC removed Indian Point Unit 2 from the repetitive multiple
degraded cornerstone column of the action matrix. Entergy continued to implement
actions associated with the FIP until the end of calendar year 2002.
Enclosure
28
The inspection scope was to review the eight effectiveness reviews conducted within the
FIP. The effectiveness reviews included: management observation of work activities;
operator burden and work-down curve for temporary alterations; review of the design
basis initiative project; optimization of the preventive maintenance program; corrective
actions in monitoring the work control process; equipment reliability actions; work
management self-assessments; and corrective action effectiveness reviews for condition
reports.
The inspector reviewed the FIP expectation, reviewed the completed effectiveness
evaluations, and discussed the evaluations with individuals assigned to perform the
reviews. The inspector compared the results and conclusions of the individual
effectiveness review with applicable performance metrics maintained by Entergy and
using past applicable NRC assessments in performance (inspection report findings and
ROP-3 end-of-cycle assessments).
b. Findings
No findings of significance were identified. The inspector concluded that selected
effectiveness reviews were not consistently self-critical. For example, the effectiveness
review for the design basis initiative project primarily focused on the quality of action
plans and efficiencies of plan implementation instead of the quality of the output products
and the amount of use of this information by design and system engineering staffs. The
NRCs evaluation also found that the work control effectiveness reviews did not explore
the quality of post-work tests, but rather highlighted processing problems associated with
post-work testing.
The NRC noted that the 2003 Indian Point Business plan provided adequate actions to
support improvements in the five key areas from the FIP. Further, self-assessments are
currently part of the business plan and areas within the plan focus on departmental self-
assessments and monitoring the quality of those assessments through a self-
assessment review board.
4OA3 Event Follow-up
.1 Licensee Event Report (LER) 2002-002-00 Restoration of Previously Isolated Portion of
Weld Channel and Containment Penetration Pressurization System,
(Closed) Licensee Event Report (LER) 2002-002-00, Restoration of Previously Isolated
Portion of Weld Channel and Containment Penetration Pressurization System, dated
August 7, 2002. On June 8, 2002, the licensee confirmed through testing that a
previously retired (because of supposed leakage) section of Zone W-11 of the weld
channel and containment penetration pressurization system (WCCPPS) was leak-tight
and should be restored to an operable status. The licensee concluded that the cause of
the premature retirement of this section of Zone W-11 was an inadequate leak test of the
subject weld channel and a poor assumption that leakage was in a section of the weld
channel embedded in concrete and, therefore, not capable of being repaired.
Enclosure
29
In addition to the broad corrective action taken under the FIP, dated January 25, 2002, to
address the human performance weaknesses which contributed to this event, the
operations manager deleted the operations department troubleshooting procedure (DAD-
40) in favor of the work control departments procedure governing troubleshooting and
repairs. The work control department procedure implements a more thorough planning,
review, approval, and closeout process which ensures a higher probability of a
satisfactory troubleshooting result. This LER is closed.
4OA5 Review of Institute of Nuclear Power Operations (INPO) Evaluation Report
The inspectors reviewed the final report of an INPO Evaluation conducted in February
2002. The inspectors identified no new findings of significance.
4OA6 Meetings, Including Exit
The inspectors met with Indian Point 2 representatives at the conclusion of the inspection
on April 9, 2003. At that time, the purpose and scope of the inspection were reviewed,
and the preliminary findings were presented. The licensee acknowledged the preliminary
inspection findings.
The inspector asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was reviewed during this
inspection.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Enclosure
1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Entergy:
W. Axelson Support Supervisor
M. Dampf Health Physics Manager
R. Deschamps Radiological Protection Superintendent
R. Decensi Technical Support Manager
R. Fucheck HP Supervisor
D. Gately Radiation Protection Coordinator
R. LaVera Radiological Engineer
R. Majes Radiological Engineer
R. Richards HP Supervisor
R. Rodino Radiological Engineer
W. Scholtens Waste Management Contractor
R. Solanto HP Supervisor
J. Stewart HP Supervisor
R. Tagliomonte Waste Management Supervisor
N. Azevedo ISI Supervisor
W. Axelson Support Supervisor
T. Burns Environmental Supervisor
J. Comiotes Director, Nuclear Safety Assessment
L. Cortopassi IP3 Training Manager
F. Dacimo Vice-President
M. Dampf Health Physics Manager
S. Davis IP2 Licence Operator Requalification Training Supervisor
R. Decensi Technical Support Manager
R. Deschamps Radiological Protection Superintendent
J. DeRoy General Manager Plant Operations, IP3
K. Finucan Emergency Planning Staff
K. Finvean Reactor Vessel Head Inspection, Assistant Project Manager
R. Fucheck HP Supervisor
D. Gately Radiation Protection Coordinator
M. Gillman IP3 Operations Manager
L. Glander Dosimetry Supervisor
J. Goebel Reactor Vessel Head Inspection, Project Manager
F. Inzirillo Manager Emergency Planning
T. Jones Nuclear Safety and Licensing
R. LaVera Radiological Engineer
R. Majes Radiological Engineer
J. McCann Nuclear Safety and Licensing Manager
F. Mitchell HP Supervisor
D. Pace VP - Engineering - ENN
J. Perrotta Quality Assurance Manager
Attachment
Attachment (contd) 2
R. Penny Manager, Engineering Programs
R. Richards HP Supervisor
K. Richett HP Technician
R. Rodino Radiological Engineer
R. Sachatello Radiological Consultant
C. Schwarz General Manager, IP2 Plant Operations
G. Schwartz Chief Engineer
H. Salmon Quality Assurance Director
M. Smith Director of IP3 Engineering
R. Solanto HP Supervisor
S. Stevens HP Technician
J. Stewart HP Supervisor
D. Sullivan-Weaver Emergency Planning Staff
J. Tuohy Design Engineering Manager
J. Wheeler Site Training Manager
F. Wilson Superintendent, Operations Training
M. Wilson Emergency Planning Staff
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Closed
LER 50-247/ 2002-002-00 Restoration of previously isolated portion of weld channel and
containment penetration pressurization system
Open/Closed
50-247/03-03-02 NCV Ineffective corrective actions associated with the 23 EDG load
swings between May 2000 and February 2003
50-247/03-03-03 NCV Improper emergent work package instructions for 22 steam
generator level bistable replacement
50-247/03-03-05 NCV Post-work test inadequate for 22 boric acid transfer pump boric
acid filter stop valve
50-247/03-03-06 NCV Failure to comply with packaging procedures
Opened
50-247/03-03-01 URI Lack of cable separation in fire areas F and J, postulated fire
compromising associated circuits.
50-247/03-03-04 URI Electrical calculation reconstitution to support offsite power design
basis (SAT load tap changer).
Attachment
Attachment (contd) 3
LIST OF DOCUMENTS REVIEWED
Sections 1EP4, Emergency Action Level and Emergency Plan Changes
Emergency Plan for Indian Point Unit Nos 1 and 2, Rev 01-02a
Indian Point 3 Emergency Plan, Rev 46
Indian Point Energy Center Emergency Plan, Rev 02-01
IP-EP-251, Alternate Emergency Operations Facility, Rev 0
IP-EP-255, Emergency Operations Facility Management and Liaisons, Rev 1, 2
IP-EP-310, Dose Assessment, Rev 0
IP-EP-410, Protective Action Recommendations, Rev 0
IP-EP-510, Meteorological, Radiological & Plant Data Acquisition System, Rev 0
IP-EP-520, Modular Emergency Assessment & Notification System (MEANS), Rev 0
IP-EP-610, Emergency Termination and Recovery, Rev 0
IP-EP-620, Estimation of Total Population Exposure, Rev 0
IC/EALs, Initiating Conditions & Emergency Action Levels, Rev 9 (IP3)
IP-1001, Determining the Magnitude of Release, Rev 17, Void (IP3)
IP-1002, Emergency Notification and Communication, Rev 27, 28 (IP2)
IP-1003, Obtaining Meteorological Data, Rev 18, Void (IP3)
IP-1004, MIDAS Computer System, Rev 16, Void (IP3)
IP-1010, Central Control Room, Rev 6, 7, 8 (IP2)
IP-1013, Protective Action Recommendations, Rev 8, (IP2)
IP-1015, Radiological Monitoring Outside the Protected Area, Rev 10 (IP2)
IP-1017, Protective Action Recommendations for the Offsite Population, Void, Rev 13
(IP3)
IP-1019, Coordination of Corporate Response, Rev 11 (IP2)
IP-1021, Manual Update, Readout & Printout of Proteus Plant Parameter Data, Canceled
(IP2)
IP-1023, Operation Support Center, Rev 19 (IP2)
IP-1026, Emergency Data Display, Rev 1 (IP2)
IP-1027, Personnel Accountability Rev 17 (IP2)
IP-1027, Emergency Personnel Exposure, Rev 13, (IP3)
IP-1030, Emergency Operations Facility, Rev 8 (IP2)
IP-1030 Emergency Operations Facility, Rev 7 (IP2)
IP-1035, Technical Support Center, Rev 17 (IP2)
IP-1050, Security, Rev 4 (IP2)
IP-1050, Accountability, Rev 28 (IP3)
IP-1054, Search and Rescue Teams, Rev 11 (IP3)
IP-2001, ED, POM, Shift Managers Procedure, Rev 16, 17 (IP3)
IP-2003 CR Watch Chemist, Rev 6 (IP3)
IP-2200, Emergency Activation of the Operations Support Center, Rev 7 (IP3)
IP-2201 OSC Manager, Rev 9 (IP3)
IP-2204, OSC Team Leader, Rev 3 (IP3)
IP-2209, OSC HP Technician, Rev 5
IP-2301, Emergency Director, Void (IP3)
IP-2302, EOF Technical Advisor & Information Liaison, Rev 10 (IP3)
IP-2310, EOF Onsite Radiological Communicator, Rev 4 (IP3)
Attachment
Attachment (contd) 4
IP-2400, Emergency Activation of the Alternate Emergency Operations Facility, Void
(IP3)
IP-2500, Security Emergency Activation Responsibilities, Rev 12 (IP3)
IP-2600, Emergency Termination & Transition to Recovery, Rev 4, Void (IP3)
IP-2601, Recovery Manager, Rev 1, Void (IP3)
IP-2602, Development of Recovery Plan, Rev 1, Void (IP3)
IP-2603, Recovery Support Group Manager, Rev 1
10CFR50.54(q) review for IPEC Emergency Plan
10CFR50.54(q) review for IP-EP-410
EP-AD-02, Emergency Planning Controlled Documents, Rev 3
EP-AD-03, Emergency Response Organization Training Program, Rev 1
Emergency Response Training Program Curriculum, Rev 16
TNG-AD-18, Emergency Response Training Program, Rev 8
QA-AD-3, IP3 Audit Program, Rev 5
Section 2OS1, Access Control to Radiologically Significant Areas
- SAO-302, Rev. 18, Radiation work permits (RWP) program
- HP-SQ-3.002, Rev. 16, Equipment and materials release requirements
- RW-SQ-4.109, Rev. 10, Radioactive material storage
- RWP 032009, Rev. 00, Assessments in RCA
- RWP 032028, Rev. 00, Non-outage vapor containment-all groups
- Radiation Protection performance goals for 2003
- Unit 2 housekeeping and area decon plan, February 25, 2003
- Quality assurance assessment report no. 02-AR-33-RP, November 11 - 15, 2002
- Continuing training - 2003, Session 1, Radiation Protection Alignment Session
Section 2OS2, ALARA Planning and Controls
- SAO-303, Rev. 11, ALARA program
- SAO-305, Rev. 10, Station ALARA committee
- IP1 and 2 Daily ALARA information for week of 02-16-2003
- IP1 and 2 Weekly exposure trend for 2003
- Pre-job, In-progress, and Post-job ALARA Reviews No.02-013 (RWP 025226) for
Outage valve work for 2R15
- Post-job review (ALARA review 02-013) for outage radioactive waste support
(RWP 025206) for 2R15
- Indian Point Energy Center/Radiation protection/2R15 outage ALARA review
- Indian Point Energy Center/Radiation protection/Strategic plan for exposure
reduction, 2003 - 2008
- IPEC ALARA committee meeting presentation handout for January 28, 2003
Attachment
Attachment (contd) 5
Section 2OS3, Radiation Monitoring Instrumentation and Protective Equipment
- Entergy South automated contamination monitor configuration, December 3,
2002
Section 2PS2, Radioactive Material Processing and Transportation
- RW-SQ-4.303, Rev. 14, Shipping cask handling procedure
- Procedures, license, and safety analysis report for the CNS 8-120B Type B
radioactive waste shipping cask, USA/9168/B(U)
Condition Reports Generated During this Inspection
IP3-2003-00480 Addresses minor issues associated with the development of the new plan.
Items include the handling of the lead accountability officer function,
description of the Safety Team Lead position, inclusion of core exit
thermal couples as instrumentation used, specifying a two hour joint news
center activation goal, distribution and updating of EALs to State and
County locations, clarification of drill applicability for the two units, and
removal of extraneous information from Table B-1.
IP3-2003-00493 Addresses review of Table B-1 staffing for a dual unit site with regards to
Technical Specification staffing requirements.
IP3-2003-00457 Addresses need to update emergency plan regarding KI when decision is
finalized by the State.
IP2-2003-01515 Scaffolding in the pipe penetration area near the containment pressure
transmitters not meeting station expectations.
IP2-2003-01520 Discrepancy between drawing and field conditions for 21 containment
spray pump discharge header drain
IP2-2002-09231 Pre-fire plan sketch for Fire Zone 90A in error
IP2-2003-00567 Fire Zone 6A discrepancies noted
IP2-2003-01673 Failure to incorporate a drawing revision to a non-operations critical
drawing
IP2 2003-01409 Unavailability time incorrect for the 22 CCW pump maintenance rule
IP2 2003-01037 Valves labels in auxiliary feedwater room do not match the check off list
IP2 2003-01161 Valve labels in the emergency diesel generator room do not match the
check off list
Condition Reports
Attachment
Attachment (contd) 6
IP2-2002-09152, IP2-2002-09054, IP2-2002-06818, IP2-2002-04701, IP2-2001-08308,
IP2-2001-05461, IP2-2001-02536,
LIST OF BASELINE INSPECTIONS PERFORMED
71111.04 Equipment Alignment 1R04
71111.05 Fire Protection 1R05
71111.06 Flood Protection Measures 1R06
71111.11 Operator Requalification 1R11
71111.12 Maintenance Effectiveness 1R12
71111.13 Maintenance Risk Assessment and Emergent Work Activities 1R13
71111.14 Personnel Performance During Non-Routine Plant Evolutions 1R14
71111.15 Operability Evaluations 1R15
71111.17 Permanent Modifications 1R17
71111.19 Post Maintenance Testing 1R19
71111.22 Surveillance Testing 1R22
71111.23 Temporary Plant Modifications 1R23
71114.04 Emergency Action Level and Emergency Plan Changes 1EP4
71114.06 Emergency Planning Drills 1EP6
71121.01 Access Control to Radiologically Significant Areas 2OS1
71121.02 ALARA Planning and Controls 2OS2
71121.03 Radiation Monitoring Instrumentation and Protective Equipment 2OS3
71122.02 Radioactive Material Processing and Transportation 2PS2
71151 Performance Indicator Verification 4OA1
71152 Problem Identification and Resolution Sample 4OA2
71153 Event Followup 4OA3
LIST OF ACRONYMS USED
AFWP auxiliary feedwater pump
ALARA as low as reasonably achievable
AOI abnormal operating instruction
BATP boric acid transfer pump
CAP corrective action program
CCR central control room
CCW component cooling water
CFR Code of Federal Regulations
CNS chem nuclear systems
COC certificate of compliance
COL check off list
CR condition report
DBI design basis initiative
DCP design change package
EAL emergency action level
EDG emergency diesel generator
EOF emergency operations facility
Attachment
Attachment (contd) 7
ESFS Engineered Safeguards Features System
FIP fundamental improvement plan
ICMs Interim Compensatory Measures
INPO Institute of Nuclear Power Operations
IP Indian Point
IP2 Indian Point Unit 2
IPEC Indian Point Energy Center
IPEEE individual plant examination for external events
ISI inservice inspection
JNC joint news center
kV kilo-volt
Kw kilo-watt
LER licensee event report
LTC load tap changer
MOP motor operated potentiometer
NCV non-cited violation
NEI Nuclear Energy Institute
NRC Nuclear Regulatory Commission
NRR Nuclear Reactor Regulation
ODCM offsite dose calculation manual
OSC operations support center
OS occupational safety
PI performance indicator
PM post maintenance
PT penetrant testing
PWT post-work test
RCA radiologically controlled area
RMS radiation monitoring system
RPM radiation protection manager
RSPS risk significant planning standard
RV reactor vessel
RWP radiation work permit
SAO station administrative order
SAT station auxiliary transformer
SDP significance determination process
SI safety injection
SOP system operating procedure
TA temporary alteration
TI temporary instruction
TS technical specifications
Attachment
Attachment (contd) 8
UFSAR Updated Final Safety Analysis Report
V volt
WCCPPS weld channel and containment penetration pressurization system
WO work order
Attachment