IR 05000247/2009007: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
 
(Created page by program invented by StriderTol)
Line 1: Line 1:
{{Adams|number = ML092040278}}
{{Adams
| number = ML092680234
| issue date = 09/25/2009
| title = IR 05000247-09-007, on 07/20/2009 - 08/13/2009, for Indian Point Unit 2, Component Design Bases Inspection
| author name = Doerflein L T
| author affiliation = NRC/RGN-I/DRS/EB2
| addressee name = Pollock J E
| addressee affiliation = Entergy Nuclear Operations, Inc
| docket = 05000247
| license number = DPR-026
| contact person =
| case reference number = FOIA/PA-2011-0258
| document report number = IR-09-007
| document type = Inspection Report, Letter
| page count = 48
}}


{{IR-Nav| site = 05000247 | year = 2009 | report number = 007 }}
{{IR-Nav| site = 05000247 | year = 2009 | report number = 007 }}


=Text=
=Text=
{{#Wiki_filter:
{{#Wiki_filter:UNITED STATES  NUCLEAR REGULATORY COMMISSION REGION I  475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 September 25, 2009  
[[Issue date::July 23, 2009]]


Mr. Joseph Site Vice President Entergy Nuclear Operations, Inc.
Mr. Joseph Site Vice President Entergy Nuclear Operations, Inc.
Line 11: Line 25:
Indian Point Energy Center 450 Broadway, GSB Buchanan, NY 10511-0249
Indian Point Energy Center 450 Broadway, GSB Buchanan, NY 10511-0249


SUBJECT: INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 -
SUBJECT: INDIAN POINT NUCLEAR GENERATING UNIT 2 - NRC COMPONENT DESIGN BASES INSPECTION REPORT NO. 05000247/2009007
NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000286/2009007


==Dear Mr. Pollock:==
==Dear Mr. Pollock:==
On June 16, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Indian Point Nuclear Generating (Indian Point) Unit 3. The enclosed report documents the inspection results, which were discussed on June 18, 2009, with you and other members of your staff.
On August 13, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Indian Point Nuclear Generating Unit 2. The enclosed integrated inspection report documents the inspection results, which were discussed on August 13, 2009, with Mr. Donald Mayer and other members of your staff.


This inspection was an examination of activities conducted under your license as they relate to the identification and resolution of problems, and compliance with the Commission=s rules and regulations and the conditions of your operating license. Within these areas, the inspection involved examination of selected procedures and representative records, observations of activities, and interviews with personnel.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.


Based on the samples selected for review, the inspectors concluded that Entergy was generally effective in identifying, evaluating, and resolving problems. Entergy personnel identified problems at a low threshold and entered them into the Corrective Action Program (CAP).
In conducting the inspection, the team examined the adequacy of selected components and operator actions to mitigate postulated transients, initiating events, and design basis accidents.


Station personnel generally screened issues appropriately for operability and reportability, and prioritized issues commensurate with the safety significance of the problems. Corrective actions addressed the identified problems and were typically implemented in a timely manner.
The inspection involved field walkdowns, examination of selected procedures, calculations and records, and interviews with station personnel.


However, the inspectors identified two violations of NRC requirements in the areas of prioritization and evaluation and effectiveness of corrective actions.
This report documents three NRC-identified findings which were of very low safety significance (Green). Two of these findings were determined to involve violations of NRC requirements.


This report documents two NRC-identified findings of very low safety significance (Green). The findings were determined to involve violations of NRC requirements. However, because of their very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs), consistent with Section VI.A.1 of the NRC=s Enforcement Policy. If you contest any NCV, you should provide a response with the basis for your denial, within 30 days of the date of this inspection report, to the U.S. Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Senior Resident Inspector at Indian Point Unit 3. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Senior Resident Inspector at Indian Point Unit 3. The information you provide will be considered in accordance with Inspection Manual Chapter 0305. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web Site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
However, because of the very low safety significance of the violations and because they were entered into your corrective action program, the NRC is treating the violations as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region 1; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Senior Resident Inspector at Indian Point Nuclear Generating Unit 2. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I and the NRC Senior Resident Inspector at Indian Point Nuclear Generating Unit 2. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for the public inspection in the NRC Public Docket Room or from the Publicly Available Records component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).


Sincerely,/RA/
Sincerely,/RA/
Raymond J. Powell, Chief Technical Support & Assessment Branch Division of Reactor Projects Docket No. 50-286 License No. DPR-64
Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety
 
Docket No. 50-247 License No. DPR-26


===Enclosure:===
===Enclosure:===
Inspection Report No. 05000286/2009007 w/
Inspection Report No. 05000247/2009007  


===Attachment:===
===w/Attachment:===
Supplemental Information  
Supplemental Information


Senior Vice President, Entergy Nuclear Operations Vice President, Operations, Entergy Nuclear Operations Vice President, Oversight, Entergy Nuclear Operations Senior Manager, Nuclear Safety and Licensing, Entergy Nuclear Operations Senior Vice President and COO, Entergy Nuclear Operations Assistant General Counsel, Entergy Nuclear Operations Manager, Licensing, Entergy Nuclear Operations C. Donaldson, Esquire, Assistant Attorney General, New York Department of Law A. Donahue, Mayor, Village of Buchanan J. G. Testa, Mayor, City of Peekskill R. Albanese, Four County Coordinator S. Lousteau, Treasury Department, Entergy Services, Inc.
=SUMMARY OF FINDINGS=
IR 05000247/2009007; 07/20/2009 - 08/13/2009; Indian Point Unit 2; Component Design


Chairman, Standing Committee on Energy, NYS Assembly Chairman, Standing Committee on Environmental Conservation, NYS Assembly Chairman, Committee on Corporations, Authorities, and Commissions M. Slobodien, Director, Emergency Planning P. Eddy, NYS Department of Public Service Assemblywoman Sandra Galef, NYS Assembly T. Seckerson, County Clerk, Westchester County Board of Legislators A. Spano, Westchester County Executive R. Bondi, Putnam County Executive C. Vanderhoef, Rockland County Executive
Bases Inspection.


=SUMMARY OF FINDINGS=
The report covers the Component Design Bases Inspection (CDBI) conducted by a team of four NRC inspectors and two NRC contractors. Three findings of very low risk significance (Green)were identified. Two of these findings were also considered to be NCVs. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using NRC Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). The cross-cutting aspects were determined using IMC 0305, "Operating Reactor Assessment Program."  Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.
IR 05000286/2009007; 06/01/2009 - 06/16/2009; Indian Point Nuclear Generating (Indian
 
===A. NRC-Identified and Self-Revealing Findings===
 
===Cornerstone: Mitigating Systems===
: '''Green.'''
The team identified a finding of very low safety significance involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergy did not verify the adequacy of design because they did not evaluate the impact of the installed Amptector discriminator instantaneous trip feature on breaker coordination.


Point) Unit 3; Biennial Baseline Inspection of the Identification and Resolution of Problems.
Following identification Entergy entered the issue into the corrective action program and performed an operability assessment and extent-of-condition review.


Two findings were identified in the areas of prioritization and evaluation and effectiveness of corrective actions. This NRC team inspection was performed by three NRC regional inspectors and one resident inspector. Two findings of very low safety significance (Green) were identified during this inspection and were classified as non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using NRC Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). The cross-cutting aspects were determined using IMC 0305, "Operating Reactor Assessment Program."  Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC=s program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, AReactor Oversight Process,@ Revision 4, December 2006.
The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of the 480Vac bus to respond to initiating events to prevent undesirable consequences. Specifically, load center Bus 6A (and 2A, 3A and 5A) would be incapable of meeting the design basis function when required if the incoming line breaker to the load center bus were to trip due to lack of coordination for a fault on a non-Class 1E circuit during a design basis accident. The finding was determined to be of very low safety significance because the design deficiency was confirmed not to result in loss of operability or functionality.


Identification and Resolution of Problems The inspectors concluded that Entergy was generally effective in identifying, evaluating, and resolving problems. Entergy personnel identified problems at a low threshold and entered them into the Corrective Action Program (CAP). For most condition reports (CRs) reviewed, the inspectors determined that site personnel screened issues appropriately for operability and reportability, and generally prioritized issues commensurate with the safety significance of the problems. The inspectors determined that causal analyses appropriately considered extent of condition, generic issues, and previous occurrences. The inspectors also determined that corrective actions addressed the identified causes and were implemented in a timely manner.
This finding was not assigned a cross-cutting aspect because the underlying cause was not indicative of current performance.  (Section 1R21.2.1.1)
: '''Green.'''
The team identified a finding of very low safety significance involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergy did not to ensure that the component cooling water pump hydraulic performance test procedures had acceptance criteria which incorporated applicable design limits sufficient to ensure continued pump operability. Specifically, if the pump flow rate had degraded to the lower limit of the acceptance band, as listed in the test acceptance criteria, the pump would not have been able to meet the design basis flow requirements at the minimum acceptable differential pressure listed in the test procedure. In addition, the iii test acceptance criteria for design basis flow rate and differential pressure had no allowance for measurement uncertainty of the test instruments. In response to this deficiency, Entergy's short-term corrective actions included initiation of a corrective action condition report and completion of an operability determination for the affected equipment.


However, the inspectors identified two violations of NRC requirements in the areas of prioritization and evaluation, and effectiveness of corrective actions. The issues were entered into Entergy's CAP during the inspection. Entergy's audits and self-assessments reviewed by the inspectors were thorough and probing.
The finding was more than minor because it was associated with the design control attribute of the Mitigating Cornerstone and affected the cornerstone objective of ensuring the capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the test acceptance criteria did not ensure that the No. 23 component cooling water pump remained capable of performing its safety function under design basis conditions. The finding had very low safety significance because it was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.


Additionally, the inspectors concluded that Entergy adequately identified, reviewed, and applied relevant industry operating experience (OE) to Indian Point Unit 3. Based on interviews, observations of plant activities, and reviews of the CAP and the Employee Concerns Program (ECP), the inspectors did not identify concerns with site personnel willingness to raise safety issues nor did the inspectors identify conditions that indicated a negative impact on the site's safety conscious work environment.
This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because Entergy's initial operability review, issue prioritization, and subsequent evaluation did not adequately assess actual pump performance.


===Cornerstone: Mitigating Systems===
[P.1 (c)]  (Section 1R21.2.1.2)
: '''Green.'''
: '''Green.'''
The inspectors identified an NCV of very low safety significance of 10 CFR 50, Criterion XVI, "Corrective Action," for Entergy's failure to identify and correct a condition adverse to quality related to 480-Volt bus 3A degraded grid protection.
The team identified a finding of very low safety significance because Entergy did not identify or evaluate material deficiencies of the city water system, as required by EN-LI-102, "Corrective Action Process."  Specifically, Entergy did not identify or evaluate several degraded pipe supports on city water system piping in the utility tunnel, which represented reasonable doubt on system operability. The city water system provides a backup water supply for the condensate storage tank, fire fighting water supply, and provides alternate cooling to selected safety-related and risk significant pumps. The finding was not a violation because the city water piping, in the utility tunnel, is not safety-related, and the utility tunnel is not a safety-related or seismic structure. Entergy entered this issue into the corrective action program, assessed operability and extent-of-condition, and repaired one of the non-functioning pipe supports to restore additional margin. The finding was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern.
 
Specifically, the piping system could have potentially collapsed if additional pipe supports became degraded. The team determined the finding was of very low safety significance because it was not a design or qualification deficiency, did not represent of an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.


Specifically, Entergy staff did not identify and implement adequate corrective actions to ensure the safety-related time delay relay, 62-1/3A, remained functional within its technical specification (TS) surveillance requirement (SR) acceptance criteria when it exhibited abnormal relay drift in October 2007. As a result, the relay drifted out of specification for a portion of the next surveillance period, which should have been reasonably avoided. Additionally, in November 2007, Entergy did not adequately evaluate past operability to determine if NRC reportability criteria per 10 CFR 50.73 were exceeded for the degraded relay condition that existed for a time longer than would be permitted by the TS action statement. Entergy entered the issue into the corrective action program as CR-IP3-2009-02664 and CR-IP3-2009-02773 which includes a final review of reportability by Entergy. The inspectors determined the finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).
iv


Specifically, the 480-Volt bus 3A degraded voltage safety-related time delay relay, 62-1/3A, was degraded and exceeded its TS SR acceptance criteria of 45 seconds during two consecutive surveillance tests. However, the inspectors determined the relay would perform its safety function with a worst-case time delay of 55.9 seconds for a non-safety injection (non-SI) degraded grid condition. The inspectors' review determined this condition would not reasonably have prevented the relay from performing its function, allowing the 480V electrical bus 3A to swap its supply from the offsite grid to the on-site 31 emergency diesel generator prior to the loss or damage of supplied equipment. The inspectors determined the significance of the finding using IMC 0609.04, "Phase 1 - Initial Screening and Characterization of Findings."  The finding was determined to be of very low safety significance (Green)because it was not a design or qualification deficiency; did not represent a loss of system safety function; and did not screen as potentially risk-significant due to external initiating events. The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution within the corrective action program component because Entergy personnel did not thoroughly evaluate the problem such that the resolution addressed the cause. (Section 4OA2.1.c) (P.1.c per IMC 0305)
This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because Entergy did not adequately implement the corrective action program with a low threshold for identifying issues.
: '''Green.'''
The inspectors identified an NCV of very low safety significance of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," paragraph (a)(2), for Entergy's failure to adequately demonstrate that the instrument air (IA) system (a)(2) performance was effectively controlled through performance of appropriate preventative maintenance. Specifically, as evidenced by repeat functional failures of IA compressor solenoid-operated unloader valves in March 2009, the IA (a)(2) performance demonstration was no longer justified in accordance with maintenance rule implementing procedure guidance or consistent with Entergy's previous June 2008 (a)(1) evaluation on the issue. Entergy entered the issue into the corrective action program as CR-IP3-2009-02716. The inspectors determined the finding was more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective of ensuring the capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).


Specifically, following repetitive maintenance-related functional failures of an instrument air compressor (solenoid-operated) unloader valve in March 2009,
[P.1(a)]  (Section 1R21.2.2.1)  
Entergy did not identify the instrument air system should be monitored in accordance with 10 CFR 50.65(a)(1) for establishing goals and monitoring against the goals.


The inspectors evaluated the significance of this finding using IMC 0609.04, "Phase 1 - Initial Screening and Characterization of Findings."  The inspectors determined that this finding was of very low safety significance (Green) because the finding was not a design or qualification deficiency; did not represent a loss of safety system function; and did not screen as potentially risk significant due to external initiating events.
===B. Licensee-Identified Violations===


The inspectors determined that this finding had a cross-cutting aspect in the area of human performance because Entergy did not ensure that available and adequate maintenance resources were applied such that a known IA system deficiency was corrected in a timely manner to prevent repeat functional failures of the instrument air compressor unloader valves. (Section 4OA2.1.c) (H.2.a per IMC 0305)
None.


=REPORT DETAILS=
=REPORT DETAILS=


==OTHER ACTIVITIES (OA)==
==REACTOR SAFETY==
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
 
{{a|1R21}}
==1R21 Component Design Bases Inspection (IP 71111.21)==
 
===.1 Inspection Sample Selection Process===
 
The team selected risk significant components and operator actions for review using information contained in the Indian Point Unit 2 Probabilistic Safety Assessment (PSA)and the NRC's Standardized Plant Analysis Risk (SPAR) model for Indian Point Unit 2.
 
Additionally, the team referenced the Risk-Informed Inspection Notebook for Indian Point Unit 2 (Revision 2.1a) in the selection of potential components and operator actions for review. In general, the selection process focused on components and operator actions that had a Risk Achievement Worth (RAW) factor greater than 1.3 or a Risk Reduction Worth (RRW) factor greater than 1.005. The components selected were located within both safety related and non-safety related systems, and included a variety of components such as pumps, breakers, ventilation fans, transformers, and valves.
 
The team initially compiled a list of components and operator actions based on the risk factors previously mentioned. Additionally, the team reviewed the previous CDBI report (05000247/2007007) and excluded the majority of those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 16 components, 5 operator actions and 6 operating experience (OE) items.
 
The team's evaluation of possible low design margin included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment also included items such as failed performance test results, corrective action history, repeated maintenance, Maintenance Rule (MR) (a)(1) status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry OE.
 
Finally, consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins. The margin review of operator actions included complexity of the action, time to complete the action, and extent-of-training on the action.
 
The inspection performed by the team was conducted as outlined in NRC Inspection Procedure (IP) 71111.21. This inspection effort included walkdowns of selected components, interviews with operators, system engineers and design engineers, and reviews of associated design documents and calculations to assess the adequacy of the components to meet design basis, licensing basis, and risk-informed beyond design basis requirements. Summaries of the reviews performed for each component, operator action, OE sample, and the specific inspection findings identified are discussed in the subsequent sections of this report. Documents reviewed for this inspection are listed in the Attachment.
 
===.2 Results of Detailed Reviews===
 
===.2.1 Detailed Component and System Reviews (16 samples)===
 
===.2.1.1 Diesel Building Ventilation Fans 318 and 323===
 
====a. Inspection Scope====
Motor control center (MCC) 26B supplies power to diesel building ventilation fans 318 and 323. The team reviewed the MCC 26B one-line and fan motor schematic diagrams to ensure the ventilation fans functioned as designed. The team also reviewed the coordination/protection calculation for load center Bus 6A incoming line and MCC 26B feeder breaker Amptector  trip settings for design basis load flow conditions and protective device coordination. The team walked down MCC 26B, the fan motor controllers, and 480Vac Bus 6A to assess the observable material condition. The team reviewed the fan motor feeder cable sizing and calculated voltage available during design basis conditions for adequacy. The load center breakers were field inspected for conformance with design basis requirements for the type of Amptector trip unit installed.
 
In particular, LSG (long, short, & ground) type breakers potentially had Amptector discriminator trip units installed, whereas LSIG (long, short, instantaneous, & ground)type breakers did not. The team reviewed corrective action condition reports (CRs) and corrective maintenance history to identify potential recurring issues affecting reliability.
 
The team also reviewed surveillance testing on Amptector trip units for adequacy of results in accordance with design basis setting requirements.
 
====b. Findings====
 
=====Introduction.=====
The team identified a finding of very low safety significance (Green) involving a NCV of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergy did not verify the adequacy of design because they did not evaluate the impact of the installed LSG trip unit discriminator feature on breaker coordination.
 
=====Description.=====
During an inspection of 480Vac Bus 6A to independently assess Entergy design control (rating and use of LSG or LSIG type breakers), the team identified that Amptector discriminator instantaneous trips existed on the incoming line, emergency diesel generator (EDG) and bus cross-tie breaker. The team also determined that Entergy had not evaluated the discriminator circuit function in the breaker coordination study. Subsequently, during their extent-of-condition review, Entergy determined that type LSG trip units in load center Buses 5A, 2A and 3A were also affected. Entergy initiated CR-IP2-2009-3065 to evaluate the Amptector type LSG trip units without the discriminator defeated.
 
The Amptector discriminator circuit functions to provide an instantaneous breaker trip unless a minimum threshold current is exceeded prior to an overload condition (fault).
 
The breaker coordination study, Calculation FEX-00141-01, "IP2 Amptector Setting Verification, Sensor and Tolerances," specified that there are no instantaneous trips for the safety-related load center incoming line, EDG and bus-tie breakers, which would allow for their coordination with downstream non-Class 1E breakers during fault conditions. The breaker coordination analysis that demonstrates the adequacy of protection is required to satisfy Entergy Standard EEN-EE-S-010-IP2, "Electrical Separation Design Criteria," Section 5.10.5, Electrical Isolation Criteria, which includes demonstration that operation of Class 1E circuits, are not degraded below an acceptable level due to shorts or faults on the non-Class 1E side.
 
The team noted that the Amptector discriminator circuit could potentially cause the instantaneous trip of the 480Vac load center bus incoming line breaker during a postulated design basis accident, due to a fault on a non-Class 1E circuit, and result in the loss of the load center. The team concluded that the electrical isolation provided for the postulated fault condition, with the subject load center breaker Amptector discriminator function not being disabled, did not satisfy the requirements of Engineering Standard EEN-EE-S-010-IP2, "Electrical Separation Design Criteria," for electrical isolation of non-Class 1E circuits. Entergy performed an operability evaluation that determined that there was sufficient Class 1E load during all design basis operating conditions that served to disable the load center bus incoming line breaker Amptector discriminator circuit function (instantaneous trip) by exceeding the discriminator's minimum threshold current. However, the team also found that the minimum threshold current setpoint calibration had not been verified by Entergy during surveillance testing.
 
Nonetheless, the team concluded there was sufficient Class 1E load current available, well in excess of the manufacturer's rated tolerance of the electrical defeat setpoint for the Amptector trip units, to provide reasonable assurance that the discriminator circuit would be electrically defeated.
 
=====Analysis.=====
The team determined that Entergy's failure to verify the adequacy of design of the installed LSG type breakers as required by Engineering Standard EEN-EE-S-010-IP2 was a performance deficiency that was reasonably within Entergy's ability to foresee and prevent prior to July 2009. The team noted that Entergy had a previous opportunity to identify this issue. Specifically, Entergy's internal review of NRC Information Notice (IN)92-29, "Potential Breaker Miscoordination Caused By Instantaneous Trip Circuitry,"
represented a missed opportunity to evaluate this condition in 1992. On June 5, 1992, engineering had reviewed IN 92-29 and incorrectly concluded that only LSIG trip devices were installed at Unit 2.
 
The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of the 480Vac bus to respond to initiating events to prevent undesirable consequences. Specifically, load center Bus 6A (and 2A, 3A and 5A) would be incapable of meeting the design basis function when required if the incoming line breaker to the load center bus were to trip due to lack of coordination for a fault on a non-Class 1E circuit during a design basis accident. The team performed a Phase 1 SDP screening, in accordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," and determined the finding was of very low safety significance (Green) because the design deficiency was confirmed not to result in loss of operability or functionality.
 
This finding was not assigned a cross-cutting aspect because the underlying cause was not indicative of current performance. Specifically, the team did not identify any LSG breaker performance issues, Amptector calibrations, or associated engineering evaluations within the last several years that would have caused Entergy to re-revisit their response to NRC IN 92-29.
 
=====Enforcement.=====
Title 10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.
 
Contrary to the above, from June 5, 1992, until August 6, 2009, Entergy did not verify the adequacy of the design for protective device coordination regarding breakers configured with Amptector discriminator instantaneous trip circuits. Specifically, the load center Bus 6A incoming line breaker discriminator unit was neither defeated with an installed jumper nor were the conditions that were required to electrically defeat the circuit evaluated to ensure breaker coordination with non-Class 1E circuits. However, because this violation was of very low safety significance, and since it was entered in Entergy's corrective action program (CAP) as CR-IP2-2009-3065 this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.  (NCV 05000247/2009007-01, Failure to Evaluate the Impact on Breaker Coordination for the Westinghouse Amptector Type LSG Trip Unit Discriminator Feature)
 
===.2.1.2 No. 23 Component Cooling Water Pump===
 
====a. Inspection Scope====
The team reviewed design documents, including drawings, calculations, procedures, and the design basis document (DBD) to determine the design requirements for No. 23 component cooling water (CCW) pump. The team reviewed hydraulic analyses to verify adequacy of net positive suction head (NPSH) and verify adequacy of surveillance test acceptance criteria for pump minimum discharge pressure at the required flow rate. The team reviewed in-service test (IST) results to verify acceptance criteria were met and any potential performance degradation was identified. In addition, the team reviewed Entergy's response and actions related to NRC Bulletin 88-04, "Potential Safety-Related Pump Loss," to assess implementation of OE related to pump minimum flow requirements, and pump-to-pump interaction. The team also reviewed electrical calculations, drawings, and pump brake horsepower requirements to determine if the motor capacity was adequate for the loading requirements. The team reviewed motor breaker Amptector settings, motor feeder cable ampacity and cable short circuit current capability to determine whether appropriate electrical protection coordination margins had been applied and whether the feeder cable had been properly sized for the maximum loading and short circuit current capability requirements.
 
The team performed a walkdown of the CCW pump area to assess the material condition of the pump and motor driver. The team reviewed preventive and corrective maintenance records to ensure that Entergy properly maintained the CCW pump. The team also reviewed corrective action documents to ensure that Entergy identified and corrected deficiencies associated with the CCW pump at an appropriate threshold.
 
====b. Findings====
 
=====Introduction.=====
The team identified a finding of very low safety significance (Green) involving a NCV of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergy did not ensure the CCW pump hydraulic performance test procedures had acceptance criteria which incorporated the applicable design limits sufficient to ensure continued pump operability.
 
=====Description.=====
During a self-assessment in March 2009, Entergy identified an IST pump test acceptance criteria deficiency (CR 2009-0868). Specifically, Entergy identified that they had not appropriately incorporated instrument uncertainty into test acceptance criteria. For the CCW pumps, Entergy determined that they remained operable based on the available margin as indicated by their January 2009 IST for each of the respective CCW pumps. On April 1, Entergy expanded corrective actions to include detailed reviews to determine whether pump tests adequately incorporated design bases analytical limits. The team noted that Entergy's evaluation was still in-progress, with a due date of mid-September 2009.
 
At Indian Point 2, design basis hydraulic performance of the CCW pumps is verified by the American Society of Mechanical Engineers (ASME) Section XI in-service testing program. The team noted that the minimum CCW pump flow rate and differential pressure requirements were developed in Westinghouse Report No. WCAP-12312, "Safety Evaluation for an Ultimate Heat Sink Temperature of 95 ºF at Indian Point Unit 2," Revision 2, January 2004. The minimum performance criterion for the CCW pumps was determined to be 3500 gpm at 215.8 feet of total developed head (TDH). The team reviewed CCW pump IST procedure 2-PT-Q030C, "23 Component Cooling Water Pump," Revision 18, and noted that the acceptance criterion for pump flow rate was in the range of 3430 to 3500 gpm at a TDH of 215.8 ft. The team concluded that the lower limit for acceptance criterion of 3430 gpm for flow rate at 215.8 TDH was less than, and therefore, non-conservative when compared to the minimum analysis value for pump flow rate of 3500 gpm determined in Westinghouse WCAP No. 12312 at a TDH of 215.8 feet. The team also noted that procedure Step 4.5.1.2, which calculated pump discharge pressure, had a value of 1.5 psi added to the recorded discharge pressure.
 
Entergy engineering personnel stated that this value was added to the discharge pressure to account for a check valve between the pump discharge and gauge pressure measuring tap, and that it was verified by field measurement. The team determined that this was not a valid number to be added to the discharge pressure because the field measurement did not account for the gauge elevation difference between the pump outlet gauge and the gauge used at the pressure tap. Using the formula for pressure drop through a check valve, the team independently determined that a more appropriate correction would be about 1.5 feet instead of 1.5 psi. Additionally, there was no allowance for instrument measurement uncertainty in the test acceptance criteria. As  a result, the team concluded that the analytical value for the pump acceptance criteria was non-conservative by 70 gpm in flow rate, and about 2 feet TDH, without accounting for instrument uncertainty.
 
Based on these non-conservative values in the CCW pump IST acceptance criteria, the team questioned the operability of the No. 23 CCW pump because Entergy's April 16, 2009, IST recorded a CCW pump flow rate of 3460 gpm at 216.0 feet TDH (compared to the design limit of 3500 gpm at 215.8 feet TDH). Using the more appropriate correction factor on discharge pressure measurement, the recorded TDH should have been 214.0 feet. The inspectors plotted the data from the IST results on the design basis pump curve, and determined that the pump did not meet the minimum hydraulic performance requirements contained in WCAP No. 12312 during the April 2009 performance test. The team concluded that the No. 23 CCW pump actually had negative margin once appropriate and conservative values for design analytical limits and instrument uncertainty were factored in. Based on the team's assessment, the data indicated that the pump actually failed the test by about 6 feet of TDH at a corrected flow rate of 3500 gpm. The team noted that Entergy had noted the "low margin" during the April 2009 IST and entered the concern into their Margin Management Database; however, they did not assess the pump for continued operability, especially considering that they had lost all of the margin from the January 2009 IST that had formed the basis of their previous operability determination.
 
The team also noted that Entergy performed the No. 23 CCW pump IST again in July 2009 without updating the IST procedure and without performing an engineering evaluation to bound the condition to ensure that they adequately maintained the design bases. The team noted that the pump appeared to have more margin based on the July IST. Subsequently, Entergy provided an evaluation based on the July IST (considering instrument uncertainty and design bases analytical limits) that showed that the pump was operable as of July 09, 2009. The team agreed that there was more margin in the July test results which indicated that the pump met its design bases requirements for flow rate and TDH. In response to the team's concerns and identified deficiencies, Entergy initiated CR 2009-3807. Entergy's additional short-term planned corrective actions included performing an apparent cause evaluation and revising the CCW IST procedure to include appropriate analytical limits and instrument uncertainty values prior to the next scheduled IST.
 
The team noted that Entergy had missed several opportunities to identify and correct this IST shortcoming based on related issues within their CAP. Specifically, in 2006, CR IP2-2006-06511 identified concerns where instrument uncertainty was not considered in pump test acceptance criteria, and assigned an action to system and design engineering to "develop new acceptance criteria to account for instrument inaccuracy where needed."  However, engineering did not complete the recommended actions from this 2006 CR. In 2007, the NRC identified a similar issue involving non-conservative analytical limits during the Indian Point Unit 3 CDBI (NCV 05000286/2007006-03, Non-Conservative Calculation for TDAFW Pump Discharge Pressure Used for Surveillance Testing). Entergy had performed an extent-of-condition review for Unit 2, but only reviewed the test acceptance criteria of the Unit 2 turbine driven auxiliary feedwater (TDAFW) pump.
 
=====Analysis.=====
The team determined that Entergy's failure to ensure that the CCW pump hydraulic performance test procedures had acceptance criteria that incorporated the limits from applicable design documents was a performance deficiency that was reasonably within Entergy's ability to foresee and prevent prior to July 2009. The team noted that Entergy had missed several opportunities to identify and correct this deficiency dating back to 2006. In addition, following identification in March 2009, Entergy did not adequately prioritize and evaluate the condition to ensure continued CCW pump operability.
 
The team determined that the performance deficiency was similar to NRC IMC 0612, Appendix E, "Examples of Minor Issues," Example 3.j, in that the deficient hydraulic test acceptance criteria resulted in a condition where there was a reasonable doubt with respect to operability of the CCW pump. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of the CCW pump to respond to initiating events to prevent undesirable consequences. Specifically, the test acceptance criterion used did not ensure that the No. 23 CCW pump remained capable of performing its safety function under design bases conditions. The team performed a Phase 1 SDP screening, in accordance with NRC IMC 0609, Attachment 4, "Phase 1 -
Initial Screening and Characterization of Findings," and determined the finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The team concluded that there was no loss of CCW safety function based on (1) Entergy's reasonable determination of continued operability based on the July IST results, (2) no significant corrective maintenance performed on No. 23 CCW pump between the January and July ISTs, and (3) review of the river water temperature trend for 2009 (a maximum river water temperature of 78 ºF was recorded in July).
 
This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because Entergy's initial operability review, issue prioritization, and subsequent evaluation failed to adequately assess actual pump performance. Specifically, on March 5, 2009, Entergy identified pump testing deficiencies related to instrument uncertainty, and subsequently identified that No. 23 CCW pump had low margin, but did not adequately prioritize and evaluate the No. 23 CCW pump's performance with respect to its required design bases to ensure continued operability during 2009.  (IMC 0305, aspect P.1(c)) 


{{a|4OA2}}
=====Enforcement.=====
==4OA2 Problem Identification and Resolution (PI&R)==
Title 10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, from January 2004 until August 10, 2009, Entergy did not ensure that the CCW design basis for pump hydraulic performance was correctly translated into the CCW IST procedures. Specifically, Entergy did not include the appropriate analytical limits and instrument uncertainties in the development of the hydraulic performance test acceptance criteria of 3500 gpm at 215.8 feet TDH for the demonstration of operability of the CCW pumps. However, because this violation was of very low safety significance, and since it was entered in Entergy's CAP as CR-IP2-2009-3087 this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.  (NCV 05000247/2009007-02, Failure to Ensure That the CCW Pump Hydraulic Performance Test Procedures Had Acceptance Criteria That Incorporated the Limits from Applicable Design Documents)
{{IP sample|IP=IP 71152B|count=1}}
 
===.2.1.3 Steam Admission Valve to the Turbine Driven Auxiliary Feedwater Pump (PCV-1139)===
 
====a. Inspection Scope====
The team inspected air-operated valve (AOV) PCV-1139 to verify its ability to meet the design basis requirements in response to transient and accident events as described in the Updated Final Safety Analysis Report (UFSAR), DBD, and Technical Specifications (TSs). The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed diagnostic test results and stroke test documentation to verify acceptance criteria were met. The team reviewed drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team reviewed the maintenance and functional history of valve PCV-1139 by sampling CRs, the system health report, and local maintenance procedures to verify that deficiencies were appropriately identified and resolved, and that the valve was properly maintained. The team reviewed the backup nitrogen supply system for PCV-1139 to determine if design assumptions were supported by procedural operation of the system. The team interviewed the AOV program and system engineers to gain an understanding of maintenance issues and overall reliability of the valve. The team also conducted several detailed walkdowns to assess the material condition of the valve and its support systems, and to ensure adequate configuration control.
 
====b. Findings====
No findings of significance were identified.
 
===.2.1.4 Engineered Safeguards Features Actuation System===
 
====a. Inspection Scope====
The team inspected the engineered safeguards features actuation system (ESFAS) to verify its ability to meet design basis requirements during plant transients and accidents. The ESFAS processes inputs from plant instrumentation and control systems using a relay based logic network to actuate controlled components (pumps, valves, fans, etc.) when the design logic for a particular ESF is satisfied. The team reviewed design calculations, drawings, plant procedures and completed surveillance tests to ensure that the system was designed, operated, and tested in accordance with design and licensing bases documents that included the ESFAS DBD, the PSA, the UFSAR and TSs. The team performed walkdowns to assess the material condition of accessible portions of the system and Entergy's configuration control. The team reviewed a sample of maintenance work orders, CRs and system health reports to assess system performance and to ensure that Entergy identified and corrected deficiencies at an appropriate threshold. The team also discussed the design documentation and maintenance history of the ESFAS with the responsible design and system engineers.
 
====b. Findings====
No findings of significance were identified.
 
===.2.1.5 Turbine Driven Auxiliary Feedwater Pump (No. 22 Auxiliary Boiler Feedwater Pump)===
 
====a. Inspection Scope====
The team reviewed design documents, including drawings, calculations, procedures, and the DBD to determine the design requirements for the TDAFW pump. The team reviewed hydraulic analyses to verify adequacy of NPSH and to verify adequacy of surveillance test acceptance criteria for pump minimum discharge pressure at the required flow rate. The team reviewed IST results to verify acceptance criteria were met and any potential performance degradation identified. The team reviewed pump actuation logic test results to ensure the TDAFW pump would start in accidents and events as described in the UFSAR. In addition, the team reviewed Entergy's response and actions related to NRC IE Bulletin 88-04, "Potential Safety-Related Pump Loss," to assess implementation of OE related to pump minimum flow requirements, and pump-to-pump interaction. The team reviewed turbine protection features, including overspeed tests, and turbine casing relief valve sizing and testing, to ensure the equipment protection features were adequate. The team reviewed condensate storage tank (CST) design criteria, including seismic qualification and usable volume calculations to ensure the TDAFW pump, in conjunction with the motor driven AFW pump had an adequate safety-grade water supply. The team reviewed the use of city water as a backup supply for the suction source for the TDAFW pump to ensure sufficient flow would be provided and to verify that Entergy adequately tested the associated valves to perform their function.
 
The team performed several walkdowns of the TDAFW pump area and supporting equipment to determine whether the alignment was in accordance with design basis and procedural requirements, and to assess the material condition of the pump and turbine.
 
The team reviewed preventive and corrective maintenance records to ensure that Entergy properly maintained the TDAFW pump. The team also reviewed corrective action documents to ensure that Entergy identified and corrected deficiencies associated with the TDAFW pump at an appropriate threshold.
 
====b. Findings====
No findings of significance were identified.
 
===.2.1.6 Station Blackout/Appendix "R" Diesel Generator===
 
====a. Inspection Scope====
The team reviewed the analysis for the station blackout (SBO)/Appendix "R" diesel generator (DG) system for load flow and short circuit current requirements to determine the design basis for maximum load, DG sizing, and protective device coordination. The team reviewed protective relay setting requirements, relay surveillance tests, and performed walkdowns of the protective relay settings to assess conformance with design bases IST. The team reviewed the vendor DG acceptance tests, and generator one-line and breaker control schematic diagrams to assess design basis requirements.
 
The team reviewed Technical Requirements Manual (TRM) surveillance requirements and surveillance test results for adequacy. The team also reviewed CRs to identify potential recurring issues that could impact system reliability. The team performed several walkdowns of the DG and associated switchgear to assess the observable material condition and Entergy's configuration control.
 
====b. Findings====
No findings of significance were identified.
 
2.1.7 No. 22 Residual Heat Removal Pump
 
====a. Inspection Scope====
The team reviewed design documents, including drawings, calculations, procedures, and the DBD, to determine the design requirements for the No. 22 residual heat removal (RHR) pump. The team reviewed hydraulic analyses to verify NPSH adequacy during the injection and sump recirculation modes of operation. The team verified adequacy of surveillance test acceptance criteria for pump minimum discharge pressure at the required flow rate. The team reviewed IST results to verify acceptance criteria were met and any potential performance degradation identified. In addition, the team reviewed Entergy's response and actions related to NRC IE Bulletin 88-04, "Potential Safety-Related Pump Loss," and Generic Letter 87-12, "Loss of RHR while the RCS is Partially Filled," to assess Entergy's implementation of OE related to pump minimum flow requirements, pump-to-pump interaction, and mid-loop operation. The team also reviewed electrical calculations, drawings, and pump brake horsepower requirements to determine if the motor capacity was adequate for the loading requirements. The team reviewed motor breaker Amptector settings, motor feeder cable ampacity and cable short circuit current capability to determine whether appropriate electrical protection coordination margins had been applied and whether the feeder cable had been properly sized for the maximum loading and short circuit current capability requirements.
 
The team performed a walkdown of the RHR pump area and supporting equipment to assess the material condition of the pump and motor driver, and reviewed a recent modification performed for room flooding mitigation. The team reviewed preventive and corrective maintenance records to ensure that Entergy properly maintained the RHR pump. The team also reviewed corrective action documents to ensure that Entergy identified and corrected deficiencies associated with the RHR pump at an appropriate threshold.
 
====b. Findings====
No findings of significance were identified.
 
2.1.8 Motor Control Center 26A
 
====a. Inspection Scope====
The team inspected MCC-26A to verify its ability to meet design basis requirements during plant transients and accidents. The MCC provides 480 volts alternating current (Vac) power to operate safety-related components that include motor operated valves (MOVs), fans and transformers. The team reviewed design calculations, drawings and plant procedures to ensure that the MCC was designed and operated in accordance with design and licensing bases documents that included the 480Vac system DBD, the PSA, the UFSAR and TSs. The team performed walkdowns to assess the material condition of the MCC and Entergy's configuration control. The team reviewed a sample of maintenance work orders, CRs and system health reports to assess system performance and to ensure that Entergy identified and corrected deficiencies at an appropriate threshold. The team also discussed the design documentation and maintenance history of the MCC with the responsible design and system engineers to assess overall reliability.
 
====b. Findings====
No findings of significance were identified.
 
===.2.1.9 Main Steam Atmospheric Steam Dump Valves (PCV-1134, 1135, 1136, & 1137)===
 
====a. Inspection Scope====
The team inspected the air-operated atmospheric steam dump valves to verify their ability to meet the design basis requirements in response to transient and accident events. The team reviewed applicable portions of the UFSAR, main steam DBD, TSs, and drawings to identify design basis requirements for these valves. The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed diagnostic test results and stroke test documentation to verify acceptance criteria were met. The team reviewed drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team reviewed the maintenance and functional history of the atmospheric steam dump valves by sampling CRs, the system health report, and local maintenance procedures to verify that deficiencies were appropriately identified and resolved, and that valves were properly maintained. The team reviewed the backup nitrogen supply system for the atmospheric steam dump valves to determine if design assumptions were supported by procedural operation of the system. The team interviewed the AOV program and system engineers to gain an understanding of maintenance issues and overall reliability of the valves. The team also conducted several detailed walkdowns to assess the material condition of the valves and their support systems, and to ensure adequate configuration control.
 
====b. Findings====
No findings of significance were identified.
 
===.2.1.1 0 DC Distribution Panel 22===
 
====a. Inspection Scope====
The team inspected DC distribution panel No. 22 to verify its ability to meet the design basis requirements in response to transient and accident events. The team reviewed the No. 22 battery system calculation with respect to the DC distribution panel No. 22 loading to determine the design basis for maximum load and minimum required voltage at selected branch circuits for conformance with design basis requirements. The team also reviewed the distribution panel vendor ratings for conformance with the design basis. The team reviewed the coordination/protection calculation to assess the design basis load and short circuit current conditions. The team walked down the distribution panel to assess the observable material condition and conformance with design documentation. The team reviewed the procurement engineering technical evaluation for replacement breakers for conformance with design basis requirements. Also, the 0team reviewed CRs and corrective maintenance history to identify potential recurring issues that could impact DC distribution system reliability.
 
====b. Findings====
No findings of significance were identified.


===.1 Assessment of the Corrective Action Program (CAP) Effectiveness===
===.2.1.1 1 Electrical Bus 2 Fast Transfer (6.9 kV Circuit Breakers UT2/UT2-ST5)===


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed Entergy's procedures that describe the CAP implementation at Indian Point Unit 3. Entergy personnel identified problems by initiating condition reports (CRs) for conditions adverse to quality, plant equipment deficiencies, industrial or radiological safety concerns, or other significant issues. Condition reports were subsequently screened for operability and reportability, categorized by significance level (A, most significant, through D, least significant), and assigned to personnel for evaluation and resolution or trending.
The team inspected the electrical bus fast transfer feature to verify its ability to meet design basis requirements during plant transients and accidents. Following a turbine trip, the electrical bus 2 fast transfer circuitry controls 6.9kV feeder circuit breakers (UT2 and UT2-ST5) to disconnect the normal feed from the unit auxiliary transformer and connect the feed from bus 5 which is powered by the station auxiliary transformer. The team reviewed the design calculations, drawings and plant procedures to ensure the bus transfer was designed and operated in accordance with design and licensing bases documents that included the UFSAR and TSs. The team reviewed surveillance test procedures to ensure that Entergy had properly incorporated the associated design features and TS requirements. The team also reviewed completed surveillance tests to ensure the acceptance criteria were met. The team reviewed the results of the circuit breaker closure time testing to ensure that they were consistent with the design documentation. The team performed walkdowns to assess the material condition of the associated switchgear and Entergy's configuration control. The team reviewed a sample of maintenance work orders, CRs and system health reports to assess system performance and to ensure that Entergy identified and corrected deficiencies at an appropriate threshold. The team also discussed the design documentation and maintenance history of the bus fast transfer system with the responsible design and system engineers to identify potential recurring issues that could impact the reliability of the fast transfer control system.


The inspectors evaluated the process for assigning and tracking issues to ensure that issues were screened for operability and reportability, prioritized for evaluation and resolution in a timely manner commensurate with their safety significance, and tracked to identify adverse trends and repetitive issues. In addition, the inspectors interviewed plant staff and management to determine their understanding of, and involvement with, the CAP.
====b. Findings====
No findings of significance were identified.


The inspectors reviewed CRs selected across the seven cornerstones of safety in the NRC's Reactor Oversight Process (ROP) to determine if site personnel properly identified, characterized, and entered problems into the CAP for evaluation and resolution. The inspectors selected items from functional areas that included chemistry, emergency preparedness, engineering, maintenance, operations, physical security, radiation safety, and oversight programs to ensure Entergy staff appropriately addressed problems identified in these functional areas. The inspectors selected a risk-informed sample of CRs issued since the last NRC PI&R inspection conducted in December 2006. Insights from the site's risk analyses were considered by the inspectors to focus the sample selection and plant walkdowns on risk-significant systems and components. The corrective action review was expanded to five years for evaluation of identified concerns within CRs relative to long-standing instrument air component reliability challenges; and agastat relay drift issues including the identification, evaluation and corrective actions associated with relay drift that could adversely impact risk significant components and/or functions. The inspectors selected items from various processes implemented at Indian Point Unit 3 to verify issues were appropriately considered for entry into the CAP. Specifically, the inspectors reviewed a sample of engineering requests, both open and closed, operator workarounds, operability determinations, system health reports, equipment problem lists, work orders (WOs), and issues entered into the Employee Concerns Program (ECP).
===.2.1.1 2===
Motor and Turbine Driven Auxiliary Feedwater Pump Flow Control Valves (FCV-406A,B,C,D & FCV-405A,B,C,D)


The inspectors reviewed CRs to assess whether Entergy personnel adequately evaluated and prioritized identified issues. The CRs reviewed encompassed the full range of evaluations, including root cause analyses, apparent cause evaluations, and common cause analyses. A sample of CRs that were categorized at lower levels (level C and level D) which did not include formal cause evaluations were also reviewed by the inspectors to ensure appropriate classification consistent with EN-LI-102, "Corrective Action Process,"
====a. Inspection Scope====
guidance. The inspectors' reviews included the appropriateness of the assigned category, the scope and depth of the causal analysis, and the timeliness of resolution. The inspectors assessed whether the evaluations identified likely causes for the issues and identified appropriate corrective actions to address the identified causes. As part of this review, the inspectors interviewed various station personnel to fully understand details within the evaluations and the proposed and completed corrective actions. The inspectors observed daily condition review group (CRG) meetings in which Entergy personnel reviewed new CRs for prioritization and assignment. The inspectors also observed a Corrective Action Review Board (CARB) meeting in which station management assessed the adequacy of recent apparent and root cause analysis reports. Further, the inspectors reviewed equipment operability determinations, reportability assessments, and extent-of-condition reviews for selected CRs to verify these specific reviews adequately addressed equipment operability, reporting of issues to the NRC, and the extent of problems.
The team inspected the air-operated feedwater flow control valves for both the motor and turbine driven AFW pumps to verify their ability to meet the design basis requirements in response to transient and accident events. The team reviewed applicable portions of the UFSAR, the main steam and AFW DBDs, and the TSs, to identify design basis requirements for these valves. The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed diagnostic test results and stroke test documentation to verify acceptance criteria were met. The team reviewed drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team reviewed the maintenance and functional history of the feedwater flow control valves by sampling CRs, the system health report, and local maintenance procedures to verify that deficiencies were appropriately identified and resolved, and that the valves were properly maintained. The team reviewed the backup nitrogen supply for the AFW system to determine if there was sufficient capacity to support design assumptions for system operation following a loss-of-instrument air. The team interviewed the AOV program and system engineers to gain an understanding of maintenance issues and overall reliability of the valves. The team also conducted several detailed walkdowns to assess the material condition of the valves and their support systems, and to ensure adequate configuration control.


The inspectors' reviews of CRs also focused on the associated corrective actions to determine whether the actions addressed the identified causes of the problems. The inspectors reviewed CRs for adverse trends and repetitive problems to determine whether corrective actions were effective in addressing the broader issues. The inspectors reviewed Entergy's timeliness in implementing corrective actions and effectiveness in precluding recurrence for significant conditions adverse to quality. The inspectors also reviewed CRs associated with NRC NCVs and findings since the last PI&R inspection to determine whether Entergy personnel properly evaluated and resolved the issues.
====b. Findings====
No findings of significance were identified.


Specific documents reviewed during the inspection are listed in the Attachment to this report.
===.2.1.1 3 Station Service Transformer No. 5===


Additionally, the inspectors conducted interviews with plant management and staff involved in implementing the site's human performance corrective action plan initiatives.
====a. Inspection Scope====
The team reviewed station service transformer No. 5 to verify its capability to provide a reliable source of offsite power from 6.9 kV electrical Bus 5 to the safety-related electrical Bus 5A. The team reviewed one line diagrams and vendor test results for impedance data, to confirm that correct transformer impedances were utilized in design analyses. The team confirmed the adequacy of the overcurrent relay setting calculation for design basis loading and protective relay setting requirements. The team walked down the transformer overcurrent protective relays to observe settings and to determine conformance with relay setting sheets. The team reviewed the transformer modification history for potential impact on the design basis. The team also walked down the transformer and switchgear to assess the observable material condition and to observe transformer temperature monitoring indicators and controls. The team also reviewed the corrective maintenance history and CRs to identify potential recurring issues that could impact system reliability.


The inspectors reviewed action plans and interviewed site management to understand the status of the site's human performance implementation of the action plan. The inspectors' interviews focused on understanding Entergy's current assessment of its human performance action plan effectiveness and focus areas for improvement since December 2008 with respect to recent human performance challenges.
====b. Findings====
No findings of significance were identified.


b. Assessment (1)  Effectiveness of Problem Identification  Based on the selected samples reviewed, plant walkdowns, and interviews of site personnel, the inspectors determined that Entergy personnel identified problems and entered them into the CAP at a low threshold. For the issues reviewed, the inspectors determined problems or concerns were documented in sufficient detail to understand the issues. The inspectors observed managers and supervisors at CRG and CARB meetings appropriately questioning and challenging CRs to ensure clarification of the issues. The inspectors determined Entergy personnel trended equipment and programmatic issues at low levels and CR descriptions appropriately included reference to repeat occurrences of issues. In general, the inspectors did not identify issues or concerns that had not been appropriately entered into the CAP for evaluation and resolution. In response to several questions and minor equipment observations identified by the inspectors during plant walkdowns, Entergy personnel promptly initiated CRs and/or took immediate action to address the issues.
===.2.1.1 4 Common Cause Failure of the Emergency Diesel Generators===


      (2)  Effectiveness of Prioritization and Evaluation of Issues  The inspectors determined that, in general, Entergy personnel appropriately prioritized and evaluated issues commensurate with their safety significance. CRs were screened for operability and reportability, categorized by significance, and assigned to a department for evaluation and resolution. The CR screening process considered human performance issues, radiological safety concerns, repetitiveness and adverse trends. The inspectors observed managers and supervisors at CRG and CARB meetings appropriately questioning and challenging CRs to ensure appropriate prioritization.
====a. Inspection Scope====
The team performed a focused review for potential common cause failure of the three EDGs. The team performed several detailed walkdowns of the EDG building to ascertain whether design or operational conditions existed that would compromise the performance of all three EDGs. In particular, the team reviewed seismic evaluations of control cabinets for EDG ventilation fans and EDG jacket water expansion tanks to ensure that the selected equipment could withstand seismic loads. The team walked down the areas external to the EDG building to look for seismic interaction potential (Seismic II/I), and assessed the seismic ruggedness of a transmission line tower located near the EDG building. The team reviewed internal flooding studies to ensure that there was no potential to flood the building and cause common cause failure of the EDGs.


The inspectors determined CRs were generally categorized for evaluation and resolution commensurate with the significance of the issues. Based on the sample of CRs reviewed, the guidance provided by the Entergy implementing procedures appeared sufficient to ensure consistency in categorization of the issues. Operability and reportability determinations were generally performed when conditions warranted and the evaluations supported the conclusions. Causal analyses appropriately considered the extent of the condition or problem, generic issues, and previous occurrences of the issue.
The team reviewed the EDG air start system configuration which included a connection between two of the EDG air start accumulators to ensure that any failure in the connecting air lines would not result in loss of air start capability for the two associated EDGs. The team reviewed EDG fuel oil sample results to ensure the quality of the fuel oil.


The inspectors, however, identified some instances where Entergy's prioritization of CRs, specific to the site-assigned categorization levels as described in Attachment 9.1 of EN-LI-102, "Corrective Action Process," was inconsistently implemented. Specifically, the inspectors identified some instances of category level D (Administrative Closure) CRs that documented conditions adverse to quality related to TS-related equipment without sufficient CR supporting documentation that would allow Entergy personnel to support a level D categorization in accordance with EN-LI-102. The inspectors' review determined that level C (Non-significant - Correction Only) categorizations would typically ensure higher management visibility and documentation of corrective actions in implementation of the corrective action process including final closure documentation to ensure operability and TS implications were fully addressed. The following instances were CRs identified by the inspectors as inconsistent in categorization of the issues in accordance with EN-LI-102:
The EDG heat exchangers are cooled by service water (SW) delivered to the building through a common buried pipe. The team reviewed recent pressure integrity test results for the buried pipe to ensure that the pipe was not experiencing any leakage. The team also conducted several detailed walkdowns of the accessible portions of the SW piping, EDG ventilation system, and fuel oil system to assess the material condition of these essential support systems, and to ensure adequate configuration control.
* CR-IP3-2007-03869: 480-Volt bus 3A relay 62 1/3A failed as found TS criteria;
* CR-IP3-2008-01599: 33 emergency diesel generator exhaust fan found not running in auto as expected; and
* CR-IP3-2009-00052: Abnormal noise audible on the 32 service water pump lower bearing. The inspectors independently evaluated the deficiencies noted above for significance in accordance with the guidance in IMC 0612, Appendix B, "Issue Screening," and Appendix E, "Examples of Minor Issues."  The inspectors determined that CR-IP3-2008-01599 and CR-IP3-2009-00052 were deficiencies of minor significance and, therefore, are not subject to enforcement action in accordance with the NRC's Enforcement Policy. While the inspectors concluded the CR documentation did not support a level D categorization, interviews conducted by the inspectors revealed sufficient information to determine the above issues were resolved adequately by Entergy staff.


However, the inspectors identified that the categorization of CR-IP3-2007-03869 as a level D contributed to a more than minor finding associated with Entergy personnel not being effective in evaluating and implementing appropriate corrective actions with respect to resolving a condition adverse to quality related to a 480-Volt safety-related time delay relay. This finding is documented in Section 4OA2.1.c.
====b. Findings====
No findings of significance were identified.


(3)  Effectiveness of Corrective Actions  The inspectors concluded that corrective actions for identified deficiencies were generally timely and adequately implemented. For significant conditions adverse to quality, corrective actions were identified to prevent recurrence. The inspectors concluded that corrective actions to address NRC NCVs and findings since the last PI&R inspection were timely and effective. There were, however, two examples where corrective actions were not fully effective, specifically:
===.2.1.1 5 Power Operated Relief Valve Block Valves (MOV-535 and MOV-536)===
* Entergy staff initiated CR-IP3-2009-00925 to document a discrepancy between the color of the emergency diesel generator (EDG) cylinder seal rings specified in the maintenance procedure (3-GNR-026-ELC) and the color of replacement cylinder seal rings provided by the vendor. Entergy personnel initiated corrective actions to update the seal ring color specified in the procedure to match the color of the seal rings provided by the vendor. The inspectors determined this corrective action was not effective because the color is not a unique identifier for the required seal rings and the vendor periodically changes the color of the supplied EDG seal rings. Entergy issued CR-IP3-2009-02599 to document the issue and the maintenance procedure has subsequently been changed to identify the required liner seal kit by part number and the specific required seal rings by diameter measurement. The inspectors concluded there was no system impact because there were no indications that incorrect seal rings were installed.
* Entergy staff initiated CR-IP3-2008-00656, in part, to revise procedure 3-PT-R177, "Pressurizer Heater Output and Backup Heater Group 31 Local Operation Test," in September 2008 to include the local testing of backup pressurizer heater groups 32 and 33. The inspectors determined that the revision of the purpose section and the acceptance criteria of procedure 3-PT-R177 could reasonably be interpreted by operators as allowing the 32 and 33 backup heater groups as able to meet the TS required acceptance criteria. The inspectors determined the current Updated Final Safety Analysis Report (UFSAR) and TS Bases only describe the 31 backup pressurizer heater group as being able to be credited to provide a remote shutdown control function in accordance with TS SR 3.3.4.2 (Remote Shutdown Instrumentation control circuit and transfer switch functionality test). The inspectors concluded the procedure, as revised, contained human error traps that could potentially allow an operator to misinterpret the TS acceptance criteria in such a way that 32 or 33 backup heater would be inappropriately credited as fulfilling the TS 3.3.4 remote shutdown function of the 31 pressurize heater group. The inspectors did not identify a situation where this misinterpretation had occurred. Additionally, Entergy staff had performed recent training of operators to preclude such an issue from happening before the procedure was revised, and had communicated that the 31 backup heater group was the only heater group able to be credited in TS 3.3.4. As a result of the review, the inspectors considered this procedural weakness an example of ineffective implementation of a corrective action that did not result in a TS being implemented inappropriately.


Entergy entered the issue into the corrective action program (CR-IP3-2009-02709).
====a. Inspection Scope====
The team inspected the electrical design and operation of the power operated relief valve (PORV) block valves. The review included the valve operation when the PORVs are used for plant pressure control at normal plant operating temperature and pressure as well as their use for plant low temperature overpressure protection (LTOP) when the plant is shut down. The team reviewed design calculations, drawings, plant procedures and completed surveillance tests to ensure that the valves were designed, operated and tested in accordance with design and licensing bases documents that included the UFSAR and TSs. The team reviewed thermal overload settings and system voltage loss calculations to verify the valves would operate under the most limiting plant conditions.


The inspectors independently evaluated the issues noted above for significance in accordance with the guidance in IMC 0612, Appendix B, "Issue Screening," and Appendix E, "Examples of Minor Issues."  The inspectors determined the deficiencies were of minor significance and, therefore, are not subject to enforcement action in accordance with the NRC's Enforcement Policy.
The team also reviewed a sample of recent system health reports, maintenance work orders and CRs to assess the performance history and condition of the valves.


Additionally, the inspectors identified one example of more than minor significance where Entergy personnel were not effective in evaluating and implementing effective corrective actions with respect to ensuring reliability of the instrument air (IA) system. This finding is documented in Section 4OA2.1.c.
====b. Findings====
No findings of significance were identified.


====c. Findings====
2.1.16 Main Steam Isolation Valve (MS-1-24)
(1) Degraded Grid Protection Time Delay Relay Exceeded Technical Specification Limits


=====Introduction:=====
====a. Inspection Scope====
The inspectors identified an NCV of very low safety significance (Green) of 10 CFR 50, Criterion XVI, "Corrective Action," for Entergy's failure to identify and correct a condition adverse to quality related to 480-Volt bus 3A degraded grid protection.
The team inspected air-operated valve MS-1-24 to verify its ability to meet the design basis requirements in response to transient and accident events, including the prevention of uncontrolled flow of steam following a steam line break. The team reviewed applicable portions of the UFSAR, the main steam DBD, and the TSs, to identify design basis requirements for the valve. The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed stroke test documentation to verify acceptance criteria were met. The team reviewed drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team reviewed the maintenance and functional history of MS-1-24 by sampling CRs, the system health report, and local maintenance procedures to verify that deficiencies were appropriately identified and resolved, and that valves were properly maintained. The team interviewed the maintenance and system engineers to gain an understanding of maintenance issues and overall reliability of the valves. The team also conducted several detailed walkdowns to assess the material condition of the valve and its support systems, and to ensure adequate configuration control.


Specifically, Entergy staff did not identify and implement adequate actions to ensure the safety-related time delay relay, 62-1/3A, remained within its TS surveillance acceptance criteria of 45 seconds.  
====b. Findings====
No findings of significance were identified.


=====Description:=====
===.2.2 Review of Low Margin Operator Actions (5 samples)===
Relay 62-1/3A is the safety-related non-safety injection (non-SI) time delay relay for the 3A electrical bus associated with the 31 emergency diesel generator. The surveillance and calibration procedure 3-PT-M62A, "480V Undervoltage/Degraded Grid Protection System Bus 2A and 3A Functional," has as-found acceptance criteria of 32.5 to 39.9 seconds. The as-left acceptance criteria following calibration are 34.4 to 38.0 seconds. In addition, TS surveillance requirement (SR) 3.3.5.2 requires the time delay relay to actuate within 45 seconds. Entergy performed 3-PT-M62A on October 11, 2007, and found relay 62-1/3A actuated at 51.3 seconds, exceeding the range allowed by TS SR 3.3.5.2. Entergy maintenance personnel re-adjusted the relay to 35.3 seconds, within the acceptable as-left range per procedure, and initiated CR-IP3-2007-03869. Entergy classified CR-IP3-2007-03869 as a level D (Administrative Closure) CR with a closure description of "close to actions as described in Condition
 
The team assessed manual operator actions and selected a sample of five operator actions for detailed review based upon risk significance, time urgency, and factors affecting the likelihood of human error. The operator actions were selected from a PSA ranking of operator action importance based on RAW and RRW values. The non-PSA considerations in the selection process included the following factors:
* Margin between the time needed to complete the actions and the time available prior to adverse reactor consequences;
* Complexity of the actions;
* Reliability and/or redundancy of components associated with the actions;
* Extent of actions to be performed outside of the control room;
* Procedural guidance to the operators; and
* Amount of relevant operator training conducted.
 
===.2.2.1 Align City Water for Backup Cooling to Safety Injection/Residual Heat Removal Pumps===
following Loss of Component Cooling Water
 
====a. Inspection Scope====
The team evaluated manual operator actions to align city water backup cooling to the safety injection (SI) and RHR pumps, following a loss of CCW event, to verify operator actions were consistent with design and licensing bases. Specifically, operator critical tasks included:
* Install temporary hoses
* Align CCW, primary water, and city water valves The team interviewed licensed and non-licensed operators, reviewed associated operating procedures and operator training, observed an in-field operator job performance measure (JPM) to install temporary hoses and align local CCW, primary water, and city water valves, and independently inventoried pre-staged equipment and tools, to evaluate the operators' ability to perform the required actions. In addition, the team walked down local piping and valves associated with the critical tasks to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions. The team also reviewed equipment deficiency reports, and performed infield observations, to assess the material condition of the associated piping, valves, and support systems.
 
In addition, the team walked down selected accessible portions of the city water system to independently assess Entergy's configuration control and the system's material condition. The walkdowns included the city water storage tank; an above ground inspection from the city water tank to the utility tunnel entrance to check for evidence of underground pipe leakage; the utility tunnel; and the AFW, RHR, SI, and charging pump rooms.
 
====b. Findings====
 
=====Introduction.=====
The team identified a finding of very low safety significance (Green) because Entergy did not identify or evaluate material deficiencies of the city water system, as required by EN-LI-102, "Corrective Action Process."  The finding was not a violation because the city water piping, in the utility tunnel, is not safety-related, and the utility tunnel is not a safety-related or seismic structure.


=====Description.=====
=====Description.=====
"  Entergy personnel tracked the relay drift within the drift monitoring program in place at the time but considered the relay drift to be an anomalous, singular data point and as such no further action or evaluation was taken in October 2007.
City water piping is routed underground from the city water storage tank to the utility tunnel, at the air monitoring house. The utility tunnel runs underground from the air monitoring house to the screen well house. At various locations throughout the tunnel, city water branch lines come off of the city water header pipe, to provide a backup water supply for several safety-related or risk significant components. The city water system is credited to mitigate the consequences of a plant fire (fire safe shutdown analysis) and a station blackout (SBO) event. The city water system also provides a backup water supply for the CST and fire fighting water supply, and provides alternate cooling to selected safety-related and risk significant pumps. The city water system is required to be operable in accordance with TRM 3.7.E.


Entergy personnel performed 3-PT-M62A at the next regularly scheduled monthly interval on November 8, 2007, and found relay 62-1/3A to actuate at 55.9 seconds, again exceeding the range allowed by TS SR 3.3.5.2. The maintenance personnel re-adjusted the relay to 35.8 seconds, within the acceptable as-left range, and initiated CR-IP3-2007-04210. Entergy classified this CR with a categorization level B and replaced the relay based on further engineering evaluation that determined the relay would likely exceed TS SR acceptance range in approximately 5 days after re-adjustment. At that time, Entergy did not determine the November 2007 as-found condition should have been evaluated for past operability and reportability considering the previous October 2007 failed test.
During a utility tunnel walkdown on July 23, 2009, the team identified a degraded pipe support on the city water header pipe. Entergy entered this issue into their CAP as CR 2009-2850, performed an extent-of-condition walkdown and a prompt operability assessment. Subsequently, Entergy identified several additional degraded supports on the city water pipe. Entergy determined that the city water system remained operable because the greatest unsupported span was not more than 22 feet. American Society of Mechanical Engineers (ASME) B31.1, "Power Piping," recommended that the maximum unsupported span not exceed 27 feet, for this size water service piping.


The inspectors determined that Entergy personnel did not appropriately identify that relay 62-1/3A exhibited excessive relay drift in October 2007 of approximately 20 seconds in a month and should have reasonably been considered abnormal drift within the CAP.
On August 4, 2009, the team performed an additional utility tunnel walkdown to independently assess Entergy's evaluation and extent-of-condition review. The team identified several additional degraded pipe supports on the city water header pipe, one of which caused the original unsupported span to increase from 22 feet to 38 feet in one section of the piping. Entergy entered this issue into their CAP as CR 2009-3046, performed an extent-of-condition walkdown and a prompt engineering analysis. Entergy concluded that although the available pipe stress margin was reduced, the city water system remained operable because the pipe stress was less than the ASME B31.1 allowable stress for the pipe. The team noted that Entergy used conservative assumptions in their analysis and concluded that the Entergy's assessment was reasonable. In addition, the team determined that the city water system was properly scoped in Entergy's MR program and the degraded supports would not have required a MR (a)(1) monitoring plan.


Specifically, the inspectors acknowledge that relays experience drift; however, it is not expected that relay drift would be of a magnitude such that TS SR 3.3.5.2 acceptance range would be exceeded in a monthly surveillance period. The inspectors determined that Entergy's implementation of its EN-LI-102, "Corrective Action Process," was not effective or consistent with CAP expectations in that Entergy personnel did not identify the issue as a potentially degraded condition on a safety-related component with corrective actions implemented to minimize continued TS SR acceptance criteria challenges during the following surveillance interval. Further, the inspectors reviewed approximately three years of historical information for this relay and did not identify previous anomalous drift of such magnitude that challenged TS SR acceptance criteria. Additionally, the inspectors determined that Entergy's drift monitoring program in place at the time was not specific or sensitive to relay drift that exceeded TS SR acceptance ranges.
Subsequently, work order 00171798 repaired one of the degraded pipe supports to reduce the unsupported span to 22 feet, thereby increasing the margin of the pipe support system. CR 2009-2850, corrective action CA-2, required a follow-up engineering analysis with a formal calculation. Entergy planned additional long-term corrective actions under their existing and on-going utility tunnel refurbishment plan.


The inspectors concluded that Entergy personnel, in November 2007, did not adequately address past operability to determine if NRC reportability criteria per 10 CFR 50.73,
=====Analysis.=====
"Licensee Event Report System," were exceeded for the degraded relay condition that existed for a time longer than would be permitted by the technical specification action statement 3.3.5, Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation, without placing the degraded voltage function channel in trip. Specifically, based on the October 2007 relay surveillance failure, the inspectors determined that Entergy's corrective actions for CR-IP3-2007-04210 should have evaluated reportability since the as-found relay failure was a repeat event from the previous month's surveillance that, based on Entergy staff evaluations, would have indicated past operability between October and November was likely affected for some portion of that timeframe.
The team determined that the failure to identify or evaluate material deficiencies of the city water system was a performance deficiency that was reasonably within Entergy's ability to foresee and prevent prior to July 2009. Specifically, Entergy did not identify or evaluate several degraded pipe supports on the city water header pipe in the utility tunnel, as required by EN-LI-102, "Corrective Action Process." As a result, the degraded supports represented reasonable doubt on the operability of the city water system. The finding was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern.


Entergy's corrective actions included the replacement of the relay in November 2007 and initiation of condition reports CR-IP3-2009-02664 and CR-IP3-2009-02773 which includes a final review of reportability by Entergy personnel.
Specifically, this risk significant piping system could have potentially collapsed if additional pipe supports became degraded. The team performed a Phase 1 SDP screening, in accordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," and determined the finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.


=====Analysis:=====
This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because Entergy did not adequately implement the CAP with a low threshold for identifying issues. Specifically, Entergy personnel performed frequent activities in the utility tunnel within the last two years, but did not identify the degraded supports and did not initiate a corrective action CR, as required by EN-LI-102, "Corrective Action Process."  (IMC 0305, aspect P.1(a))
The inspectors identified a performance deficiency in that Entergy did not promptly identify and correct a condition adverse to quality associated with the 480-Volt degraded grid protection time delay relay that was within Entergy's ability to foresee and correct and should have been prevented.


The inspectors determined the finding is more than minor because it is associated with equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the 480-Volt bus 3A degraded voltage safety-related time delay relay, 62-1/3A, was degraded and exceeded its TS SR acceptance criteria of 45 seconds during two consecutive surveillance tests. However, the inspectors determined the relay would perform its safety function with a worst-case time delay of 55.9 seconds for a non-SI degraded grid condition. The inspectors' review determined this condition which would not have reasonably prevented the relay from performing its function, allowing the 480V electrical bus 3A to swap its supply from the offsite grid to the on-site 31 emergency diesel generator prior to the loss or damage of any supplied equipment. Additionally, accident scenarios involving a degraded grid voltage with an SI condition were unaffected. The inspectors determined the significance of the finding using IMC 0609.04, "Phase 1 - Initial Screening and Characterization of Findings."  The finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency; did not represent a loss of system safety function; and did not screen as potentially risk-significant due to external initiating events. The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution within the corrective action program component because Entergy personnel did not thoroughly evaluate the problem such that the resolutions addressed causes. (P.1.c per IMC 0305)
=====Enforcement.=====
Enforcement action does not apply because the performance deficiency did not involve a violation of a regulatory requirement. Entergy entered this issue into their CAP as CR IP2-2009-2850 and 3046. Because this finding does not involve a violation of regulatory requirements and has very low safety significance, it is identified as FIN 05000247/2009007-03. (FIN 050000247/2009007-03, Failure to Identify Several Degraded City Water System Pipe Supports in the Utility Tunnel)


=====Enforcement:=====
===.2.2.2 Primary Feed and Bleed Cooling following Loss of Main and Auxiliary Feedwater===
10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that measures be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to the above, from October 11 to November 8, 2007, Entergy personnel did not implement measures to promptly identify and correct a condition adverse to quality associated with excessive drift for the 480-Volt degraded grid protection time delay relay, 62-1/3A, which resulted in the relay actuation time being outside the TS SR 3.3.5.2 acceptance range. Because this violation was of very low safety significance and was entered into Entergy's corrective action program (CR-IP3-2009-02664 and CR-IP3-2009-02773), this violation is being treated as an NCV, consistent with section VI.A.1 of the NRC Enforcement Policy. (NCV 05000286/2009007-01: Degraded Grid Protection Time Delay Relay Exceeded Technical Specification Limits.)    (2) Instrument Air 10 CFR 50.65(a)(2) Performance Demonstration Not Met 


=====Introduction:=====
====a. Inspection Scope====
The inspectors identified an NCV of very low safety significance (Green) of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," paragraph (a)(2), for Entergy's failure to adequately demonstrate the instrument air (IA) system (a)(2) performance was effectively controlled through performance of appropriate preventive maintenance. Specifically, as evidenced by repeat functional failures of IA compressor solenoid-operated unloader valves in March 2009, the IA (a)(2) performance demonstration was no longer justified in accordance with maintenance rule implementing procedure guidance or consistent with Entergy's previous June 2008 (a)(1) evaluation of the issue.
The team evaluated manual operator actions to establish primary feed and bleed, following a complete loss of main feedwater and AFW (e.g., loss of secondary heat sink), to verify operator actions were consistent with design and licensing bases.


=====Description:=====
Specifically, operator critical tasks included:
The IA system is a non-safety, risk significant system that is scoped within the maintenance rule because it is a structure, system, or component (SSC) required to mitigate accidents/transients, identified in emergency operating procedures, and its failure could cause a reactor scram. The primary maintenance rule function of the IA system is to provide dry filtered air for various instrument and control devices within the plant during all modes of operation. In September 2007, a solenoid-operated unloader valve failure occurred on the 32 IA compressor causing continuous unloading of the compressor. This failure was determined by Entergy personnel to be a maintenance rule functional failure per Entergy procedure EN-DC-205, "Maintenance Rule Monitoring."  In January 2008, a similar unloader valve failure occurred on the 31 IA compressor. This failure was determined by Entergy personnel to be a maintenance rule repeat functional failure. Entergy staff evaluated the IA system for monitoring under 10 CFR 50.65(a)(1) per EN-DC-206,  
* Trip reactor coolant pumps (RCPs)
"Maintenance Rule (a)(1) Process."  Entergy staff completed their 10 CFR 50.65(a)(1)evaluation in June 2008 and concluded the IA system would continue to be monitored in accordance with 10 CFR 50.65(a)(2) because the failures of the unloader valves were related to a vibration condition and not indicative of maintenance effectiveness issues.
* Initiate SI
* Open both pressurizer PORV block valves
* Open both pressurizer PORVs
* Verify SI flow
* Verify PORVs open The team interviewed licensed operators, reviewed associated operating procedures and operator training, and observed a tabletop demonstration of a loss of secondary heat sink, to evaluate the operators' ability to perform the required actions. In addition, the team walked down main control room panels to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions.
 
The team also walked down selected in-field components and reviewed equipment deficiency reports, engineering evaluations, and surveillance test results to assess the material condition of the associated pumps, valves, and support systems.
 
====b. Findings====
No findings of significance were identified.


Specifically, site personnel determined the direct cause was excessive vibration on the air compressor control panel, which houses the solenoid-operated unloader valve, and is mounted directly on the air compressor casing. Entergy staff completed an engineering change (EC) in June 2008 to correct the vibration issue by relocation of the air compressor control panel from the compressor casing to the seismically-qualified decking next to the compressor, thus eliminating the excessive vibration. Entergy staff further supported its June 2008 (a)(1) evaluation by concluding that because the cause was known and corrective actions were identified to address the vibration issue with an expectation of completion prior to the March 2009 refueling outage, the IA system did not need to be monitored per 10 CFR 50.65(a)(1). In October 2008, the plant's Maintenance Rule Expert Panel met and approved the decision to continue to monitor the IA system in accordance with 10 CFR 50.65(a)(2).
===.2.2.3 Align Condensate for Secondary Heat Removal following Loss of Main and Auxiliary Feedwater===


Due to anticipated resource challenges in the normal work control process, the EC was planned to be worked by the Fix-It-Now team. No interim corrective actions were implemented by site personnel to preclude further failures of the unloader valves prior to the expected completion of the EC. In December 2008, an additional maintenance rule repeat functional failure of an unloader valve occurred on the IA system. Entergy staff continued to conclude monitoring of the IA system per 10 CFR 50.65(a)(2) was appropriate based on its June 2008 (a)(1) evaluation. Entergy personnel continued to experience various scheduling, coordination, and procurement issues that prevented the EC from being implemented prior to, during, or since the March 2009 RFO.
====a. Inspection Scope====
The team evaluated manual operator actions to establish condensate flow to at least one steam generator (SG), following a complete loss of main feedwater and AFW (e.g.,
loss of secondary heat sink), to verify operator actions were consistent with design and licensing bases. Specifically, operator critical tasks included:
* Defeat feedwater isolation signal
* Block SI actuation signal
* Depressurize at least one SG to less than condensate pump discharge pressure
* Open feedwater flow control valves The team interviewed licensed and non-licensed operators, reviewed associated operating procedures and operator training, observed a tabletop demonstration of a loss of secondary heat sink, observed an in-field operator JPM to install a temporary instrument air control line on a feedwater regulating bypass valve, and independently inventoried pre-staged equipment and tools, to evaluate the operators' ability to perform the required actions. The team walked down main control room panels and observed an in-field simulation of the local manual actions to disconnect and lift an electrical wire from a control relay to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions. The team also walked down selected in-field components and reviewed equipment deficiency reports to assess the material condition of the associated pumps, valves, and support systems.


Subsequently, three additional unloader valve failures occurred between March 2009 and June 2009. Entergy staff continued to conclude that monitoring of the IA system per 10 CFR 50.65(a)(2) was appropriate based on the June 2008 (a)(1) evaluation even though their (a)(1) evaluation basis relied on correcting the vibration problem prior to the March 2009 refueling outage.
====b. Findings====
No findings of significance were identified.


The inspectors determined that Entergy's maintenance rule procedures and guidance from NEI 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," would allow initial maintenance rule functional failures to be considered non-maintenance effectiveness issues if the cause is known and corrective actions are in-place to address the issue in a reasonable timeframe. However, the inspectors determined it is not appropriate nor consistent with NEI 93-01 guidance to consider continued IA valve failures as non-maintenance effectiveness issues considering the original corrective actions to implement an engineering change were not completed as planned or as expected per Entergy's June 2008 (a)(1) evaluation nor were interim corrective actions implemented to minimize repeat failures. The inspectors further determined that in March 2009, the continued repeat valve failures indicated the IA system's performance was not being monitored and controlled effectively such that the system's (a)(2) performance demonstration was no longer justified.
===.2.2.4 Early Isolation of Ruptured Steam Generator===


Entergy personnel entered the issue into the CAP as CR-IP3-2009-02716 to evaluate the maintenance rule monitoring status of the IA system and current work schedule of the EC implementation date.
====a. Inspection Scope====
The team evaluated manual operator actions to prevent overfilling a ruptured SG, during a postulated design basis SG tube rupture (SGTR), to verify operator actions were consistent with design and licensing bases. Specifically, operator critical tasks included:
* Identify the ruptured SG
* Isolate main steam flow from the ruptured SG
* Stop main and auxiliary feedwater flow into the ruptured SG The team interviewed licensed operators and operator simulator instructors, reviewed associated operating procedures and operator training, and observed operator response during a simulator scenario of a SGTR event, to evaluate the operators' ability to perform the required actions. The team walked down applicable control panels in the simulator and the main control room to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions. The team also walked down selected in-field components and reviewed equipment deficiency reports to assess the material condition of the associated pumps, valves, and support systems.


=====Analysis:=====
====b. Findings====
The inspectors determined the failure to adequately demonstrate the IA system (a)(2) performance was effectively controlled through performance of appropriate preventive maintenance was a performance deficiency within Entergy personnel's ability to foresee and correct and should have been prevented.
No findings of significance were identified.


The inspectors determined the finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the solenoid-operated valve failures present a challenge to the reliability of the IA system due to the system's vulnerability to continued repeat failures. This finding was also similar to the more-than-minor example 7.b found in IMC 0612 Appendix E in that Entergy staff did not identify that the IA system should be monitored in accordance with 10 CFR 50.65(a)(1) and establish goals and monitor against those goals. The inspectors determined the significance of the finding using IMC 0609.04, "Phase 1 - Initial Screening and Characterization of Findings."  The finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency; did not represent a loss of system safety function; and did not screen as potentially risk-significant due to external initiating events. The inspectors determined that this finding had a cross-cutting aspect in the area of human performance because Entergy did not ensure that available and adequate maintenance resources were applied such that a known IA system deficiency was corrected in a timely manner to prevent repeat functional failures of the instrument air compressor unloader valves. (H.2.a per IMC 0305)
===.2.2.5 Align City Water for Backup Cooling to Charging Pumps following Loss of Component===
Cooling Water


=====Enforcement:=====
====a. Inspection Scope====
10 CFR 50.65(a)(1) requires, in part, that holders of an operating license shall monitor the performance or condition of SSCs within the scope of the monitoring program as defined in 10 CFR 50.65(b) against licensee-established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions. 10 CFR 50.65(a)(2) states, in part, that monitoring as specified in 10 CFR 50.65(a)(1) is not required where it has been demonstrated that the performance or condition of an SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended function. Contrary to the above, Entergy personnel did not demonstrate that performance of the IA system continued to be effectively controlled through the performance of appropriate preventive maintenance in that continued, repetitive, maintenance preventable failures of the IA compressor solenoid-operated unloader valves occurred during March 2009.
The team evaluated manual operator actions to align city water backup cooling to the charging pumps, following a loss of CCW event, to verify operator actions were consistent with design and licensing bases. Specifically, operator critical tasks included:
* Align charging pump in manual at maximum speed
* Install a temporary hose
* Align CCW and city water valves The team interviewed licensed and non-licensed operators, reviewed associated operating procedures and operator training, observed a tabletop demonstration of a loss of CCW, observed an in-field operator JPM to install a temporary hose and to align local CCW and city water valves, and independently inventoried pre-staged equipment and tools, to evaluate the operators' ability to perform the required actions. In addition, the team walked down local piping and valves associated with the critical tasks to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions. The team also reviewed equipment deficiency reports, as well as direct observation, to assess the material condition of the associated piping, valves, and support systems.


Following these failures, Entergy did not place the instrument air system under 10 CFR 50.65(a)(1) for establishing goals and monitoring against those goals. Because this violation was of very low safety significance and was entered into Entergy's corrective action program (CR-IP3-2009-02716), this violation is being treated as an NCV, consistent with section VI.A.1 of the NRC Enforcement Policy (NCV 05000286/2009007-02: Instrument Air 10 CFR 50.65 (a)(2) Performance Demonstration Not Met).
In addition, the team walked down selected accessible portions of the city water system to independently assess Entergy's configuration control and the system's material condition. The walkdowns included the city water storage tank; an above ground inspection from the city water tank to the utility tunnel entrance to check for evidence of underground pipe leakage; the utility tunnel; and the AFW, RHR, SI, and charging pump rooms.


===.2 Assessment of the Use of Operating Experience (OE)===
====b. Findings====
No additional findings of significance were identified.  (See Section 1R21.2.2.1 for a city water related finding.)
 
===.2.3 Review of Industry Operating Experience and Generic Issues (6 samples)===
 
The team reviewed selected OE issues for applicability at Indian Point Unit 2. The team performed a detailed review of the OE issues listed below to verify that Entergy had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.
 
===.2.3.1 Operating Experience Smart Sample FY 2008-01 -===
Negative Trend and Recurring Events Involving Emergency Diesel Generators


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors selected a sample of CRs associated with the review of industry OE to determine whether Entergy personnel appropriately evaluated the OE information for applicability to Indian Point Unit 3 and had taken appropriate actions, when warranted.
NRC Operating Experience Smart Sample (OpESS) FY 2008-01 is directly related to NRC IN 2007-27, "Recurring Events Involving Emergency Diesel Generator Operability" and NRC IN 2007-36, "Emergency Diesel Generator Voltage Regulator Problems."  The team reviewed Entergy's evaluation of IN 2007-27 and IN 2007-36 and their associated corrective actions. The team reviewed Entergy's EDG system health reports, EDG CRs and work orders, the leakage database, and surveillance test results to verify that Entergy appropriately dispositioned EDG concerns. Additionally, the team independently walked down the three EDGs and SBO/Appendix "R" DG on several occasions to inspect for indications of vibration-induced degradation on EDG piping and tubing and for any type of leakage (air, fuel oil, lube oil, jacket water). The team also directly observed the No. 21 EDG monthly surveillance run on July 21, 2009, and performed pre and post-run walkdowns to ensure Entergy maintained appropriate configuration control and identified deficiencies at a low threshold.
 
====b. Findings====
No findings of significance were identified.
 
===.2.3.2 NRC Information Notice 2007-06: Potential Common Cause Vulnerabilities in Essential===
Service Water Systems
 
====a. Inspection Scope====
The team evaluated Entergy's applicability review and disposition of NRC IN 2007-06.
 
The IN informed licensees of a potential common cause failure mechanism of SW systems due to external corrosion of piping that could lead to catastrophic failure. The team reviewed Entergy's evaluation of this issue. Specifically, the team reviewed corrective action documents, interviewed plant engineers, and walked down selected portions of the SW system, including the below grade SW pump pit and Zurn strainer pit, to verify Entergy had appropriately evaluated the OE.


The inspectors reviewed CR evaluations of OE documents associated with a sample of NRC generic letters and information notices to ensure that Entergy adequately considered the underlying problems associated with the issues for resolution via their CAP. The inspectors also observed CRG and CARB meetings to determine if industry OE was considered during the CR screening and resolution process. A list of the documents reviewed is included in the Attachment to this report.
====b. Findings====
No findings of significance were identified.


b. Assessment  The inspectors determined that Entergy staff appropriately considered industry OE information for applicability, and used the information for corrective and preventive actions to identify and prevent similar issues when appropriate. The inspectors determined that OE was appropriately applied and lessons learned were communicated and incorporated into plant operations and procedures when applicable. The inspectors observed that industry OE was routinely discussed and considered during the conduct of CRG and CARB meetings.
===.2.3.3 NRC Information Notice 2006-31: Inadequate Fault Interrupting Rating of Breakers===


====c. Findings====
====a. Inspection Scope====
The team reviewed Entergy's disposition of IN 2006-31. The IN discussed industry events and concerns associated with inadequate fault interrupting rating of breakers.
 
The team reviewed the disposition of the IN as documented by Entergy in CR-IP3-2007-01778 (the review was also applicable to IP2) and noted that engineering had concluded that design calculations and breaker ratings were adequate. The team reviewed the evaluation and the supporting short circuit analysis for IP2 and determined that Entergy had appropriately dispositioned this OE item.
 
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


===.3 Assessment of Self-Assessments and Audits===
===.2.3.4 NRC Information Notice 2005-30: Safe Shutdown Potentially Challenged by Unanalyzed Internal Flooding Events and Inadequate Design===


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed a sample of Quality Assurance (QA) audits, including a review of several of the findings from the most recent audit of the CAP, and a variety of self-assessments focused on various plant programs. These reviews were performed to determine if problems identified through these assessments were entered into the CAP, when appropriate, and whether corrective actions were initiated to address identified deficiencies. The effectiveness of the audits and assessments was evaluated by comparing audit and assessment results against self-revealing and NRC-identified observations made during the inspection. A list of documents reviewed is included in the to this report.
The team reviewed Entergy's disposition of IN 2005-30. This IN discussed recent industry events where it was discovered that safe shutdown was potentially challenged by unanalyzed flooding events and inadequate design. The team reviewed the disposition of the IN as documented by Entergy in CR OEN-2005-00482, corrective action CA-9, for both units. In this CR, Entergy had discussed the evaluation of internal flooding for Units 2 and 3, and determined that the internal flooding issues discussed in IN 2005-30 had been previously evaluated, and concluded that there were no new or additional flooding scenarios associated with the IN. Entergy determined that the design was adequate and that no additional design modifications were required. The team reviewed corrective action documents, interviewed plant engineers, and walked down accessible portions of safety-related systems (e.g., RHR pump rooms, EDGs, electrical switchgear, AFW) looking for flood-related vulnerabilities to verify that Entergy had appropriately evaluated the OE.
 
====b. Findings====
No findings of significance were identified.


b. Assessment  The inspectors concluded that QA audits and self-assessments were critical, thorough, and generally effective in identifying issues. The inspectors observed that these audits and self-assessments were completed by personnel knowledgeable in the subject areas and were completed to a sufficient depth to identify issues that were then entered into the CAP for evaluation. Corrective actions associated with the issues were implemented commensurate with their safety significance. Entergy managers evaluated the results and initiated appropriate actions to focus on areas identified for improvement.
===.2.3.5 NRC Information Notice 2008-09: Turbine-Driven Auxiliary Feedwater Pump Bearing Issues===


====c. Findings====
====a. Inspection Scope====
The team evaluated Entergy's applicability review and disposition of NRC IN 2008-09. The NRC issued the IN to alert licensees to issues with TDAFW pumps, as they relate to the importance of having accurate maintenance instructions and effective post-maintenance tests (PMTs). Entergy concluded that their maintenance procedures and PMT practices were adequate. In particular, engineering determined that, in addition to PMTs, they monitor the bearing temperature and vibration of the pump every time the TDAFW pump is run, as well as take oil samples for analysis. The team reviewed maintenance procedures, corrective action documents and interviewed plant personnel to assess the adequacy of Entergy's testing and maintenance procedures with respect to monitoring TDAFW pump bearing performance. The team also conducted several detailed walkdowns to assess the material condition of the TDAFW pump and its support systems, and to ensure adequate configuration control.
 
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


===.4 Assessment of Safety Conscious Work Environment===
===.2.3.6 NRC Information Notice 1995-10, Potential for Loss of Automatic Engineered Safety Features Actuation===


====a. Inspection Scope====
====a. Inspection Scope====
During interviews with station personnel, the inspectors assessed aspects of the safety conscious work environment at Indian Point Unit 3. Specifically, as part of personnel interviews during the inspection, the inspectors asked questions to identify whether station personnel were hesitant to raise safety concerns to their management and/or the NRC.
The team evaluated Entergy's applicability review and disposition of NRC IN 95-10. The NRC issued the IN to alert licensees to potential design issues that could result in a fault on a non-safety circuit adversely impacting the power supply to the engineered safeguards actuation system. The team reviewed Entergy's associated evaluation, the ESFAS DBD, and ESFAS drawings and determined that Entergy had appropriately dispositioned this OE item.


The inspectors also interviewed the station ECP coordinator to determine what actions were implemented to ensure employees were aware of the program and its availability with regard to raising concerns. The inspectors reviewed a number of ECP files to ensure that issues were entered into the CAP when appropriate.
====b. Findings====
No findings of significance were identified.


b. Assessment  During interviews, plant staff expressed a willingness to use the CAP to identify plant issues and deficiencies and stated that they were willing to raise safety issues. The inspectors noted that no one interviewed stated that they personally experienced or were aware of a situation where there were indications an individual had been hesitant to raise a safety issue. All persons interviewed demonstrated an adequate knowledge of the CAP and ECP. Based on these limited interviews, the inspectors concluded that there was not evidence of significant challenges to the free flow of information regarding safety concerns.
==OTHER ACTIVITIES==
{{a|4OA2}}
==4OA2 Identification and Resolution of Problems (IP 71152)==


====c. Findings====
The team reviewed a sample of problems that Entergy had previously identified and entered into the CAP. The team reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions.
 
In addition, CRs written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problem into the CAP. The specific corrective action documents that were sampled and reviewed by the team are listed in the Attachment.
 
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


{{a|4OA6}}
{{a|4OA6}}
==4OA6 Meetings, Including Exit==
==4OA6 Meetings, including Exit==
On June 18, 2009, the inspectors presented the inspection results to Mr. Joseph Pollock, Site Vice President, and to other members of the Entergy staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in the report.


ATTACHMENT:
On August 13, 2009, the team presented the inspection results to Mr. Donald Mayer, Director, Unit 1 and Special Projects (Acting Site Vice President), Mr. Anthony Vitale, General Manager, Plant Operations, and other members of Entergy management. The team verified that no proprietary information is documented in the report.
 
ATTACHMENT  


=SUPPLEMENTAL INFORMATION=
=SUPPLEMENTAL INFORMATION=
Line 225: Line 499:
==KEY POINTS OF CONTACT==
==KEY POINTS OF CONTACT==


===Licensee personnel===
Entergy Personnel
: [[contact::B. Altadonna]], Program and Components Engineer
: [[contact::N. Azevedo]], Engineering Programs 
: [[contact::J. Balletta]], Supervisor, Operations Support
: [[contact::T. Beasley]], System Engineer
: [[contact::J. Bencivenga]], Design Engineer
: [[contact::P. Bowe]], Engineer, Civil Design
: [[contact::C. Bristol]], Maintenance Engineer
: [[contact::P. Conroy]], Director of Nuclear Safety Assurance
: [[contact::J. Coulter]], Predictive Maintenance Engineer
: [[contact::K. Curley]], System Engineer
: [[contact::G. Dahl]], Specialist, Licensing
: [[contact::M. Dries]], System Engineer
: [[contact::T. Gander]], Operations Procedure Group
: [[contact::D. Gayner]], PRA Engineer
: [[contact::C. Ingrassia]], System Engineer
: [[contact::E. Kenney]], AOV Program Engineer 
: [[contact::C. Kocsis]], Operations Training
: [[contact::M. Koutsakos]], System Engineer
: [[contact::C. Laverde]], Component Engineer
: [[contact::L. Liberatori]], Design Engineer
: [[contact::D. Mayer]], Director, Unit 1 and Special Projects
: [[contact::T. McCaffrey]], Manager, Design Engineer
: [[contact::B. McCarthy]], Operations Assistant Manager
: [[contact::V. Myers]], Design Engineering Supervisor
: [[contact::R. Parks]], EOP Coordinator
: [[contact::M. Radvansky ]], Design Engineer
: [[contact::H. Robinson]], Design Engineer
: [[contact::R. Schimpf]], Design Engineer
: [[contact::R. Sergi]], Design Engineer
: [[contact::B. Shepard]], I&C Design Engineer
: [[contact::J. Timone]], Component Engineer
: [[contact::A. Vitale]], General Manager, Plant Operations
: [[contact::R. Walpole]], Licensing Manager
: [[contact::C. Wilson]], System Engineer 
: [[contact::A. Zografos]], Design Engineer


Joe Pollock, Site Vice President
Attachment
Tony Vitale, General Manager Plant Operations
Don Mayer, Director, Unit 1
Tom Orlando, Director, Engineering
Bob Walpole, Manager, Licensing
John Donnelly, Manager, Corrective Action & Assessment
John Dinelli, Assistant Operations Manager, Unit 3
Carl Smyers, Assistant Operations Manager, Operations Support
Tim Garvey, Supervisor of Emergency Planning Infrastructure
George Dahl, Licensing Engineer
John Hill, Design I&C Engineering Supervisor
Joe Reynolds, Senior Specialist, Corrective Actions & Assessment
Victor Soohoo, Instrument Air System Engineer
Tom Flynn, Quality Control Specialist
Mario DeGenova, Mechanical Systems Engineer
Patrick Cloughessy, Maintenance Rule Coordinator
Michael Dries, Mechanical System Engineer
Lou Lubrano, Component Engineer
Bob Lee, IST Engineer
Jarvis Miu, IST Engineer
Christopher Ingrassia, System Engineer
Vincent Andreozzi, System Engineering Electrical Supervisor
Paul Bode, OE Coordinator
Bruce Shepard, Design Engineer - I&C
John Balletta, Control Room Supervisor
Dan Morales, System Engineer - Electrical I&C
Abdul Bokhari, Design Engineer - I&C and EQ
John Bencivenga, Design Engineer - Mechanical
Bill Mahlmeister, Design Engineer - Electrical
Herb Robinson, Design Engineer - Electrical
Ovidio Ramirez, Jr., System Engineer - Electrical
A-2 
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==


===Opened and Closed===
==LIST OF ITEMS==
: 05000286/2009007-01 NCV  Degraded Grid Protection Time Delay Relay Exceeded Technical Specification Limits (Section
 
4OA2.1.c)
===OPENED, CLOSED AND DISCUSSED===
: 05000286/2009007-02 NCV  Instrument Air 10 CFR 50.65(a)(2) Performance Demonstration Not Met. (Section 4OA2.1.c)   
 
Open and  
===Closed===
: [[Closes finding::05000247/FIN-2009007-01]] NCV   Failure to evaluate the impact on breaker coordination for the Westinghouse
: Amptector type LSG trip unit discriminator
feature. (Section 1R21.2.1.1)
: [[Closes finding::05000247/FIN-2009007-02]] NCV   Failure to ensure that the CCW pump hydraulic performance test procedures had
acceptance criteria that incorporated the
limits from applicable design documents.  
(Section 1R21.2.1.2)
: [[Closes finding::05000247/FIN-2009007-03]] FIN  Failure to identify several degraded city water system pipe supports in the utility
tunnel. (Section 1R21.2.2.1)   


==LIST OF DOCUMENTS REVIEWED==
==LIST OF DOCUMENTS REVIEWED==
Audits and Self-Assessments
Audits and Self-Assessments
: QA-03-2007-IP-1
: IP3LO-2009-00005, Component Design Bases Inspection for Indian Point 2 IPEC Focused Self-Assessment Report, dated 4/15/09 
: QA-14-2007-IP-1
===Calculations===
: QA-04-2008-IP-1
: 18.03.F02.007, Air Operated Gate and Globe Valve Component Calculations, Rev. 0
: QA-10-2008-IP-1
: 41008.01, Control Room Panel Seismic Evaluation, Rev. 4
: QA-03-2009-IP-1
: 60817-2, 480V DB Circuit Breaker Setting for the 250HP Component Cooling Pump Motors,
: LO-IP3LO-2007-00073
: 2/17/86
: LO-IP3LO-2007-00129
: 60817-4, 480V DB Circuit Breaker Setting for the 400HP Residual Heat Removal Pump Motors, Rev. 1
: LO-IP3LO-2007-00171
: CN-POE-01-05, SG Pressure EOP Setpoint Analysis, Rev. 3
: LO-IP3LO-2007-00226
: ECX-00001, TOR Impedance Summary, Rev. 0
: LO-IP3LO-2007-00287
: EGP-S36-002, EDG Building Ventilation System Upgrade Ampacity & Voltage Drop Calculations, Rev. 0
: LO-IP3LO-2007-00297
: FEX-00141, IP2 Amptector Setting Verification, Sensor and Tolerances, Rev. 1
: LO-IP3LO-2008-00031
: FEX-00143, IP2 Load Flow Analysis of the Electrical Distribution System, Rev. 1
: LO-IP3LO-2008-00103
: FEX-00204, Station Battery 22 System Calculation, Rev. 1
: LO-IP3LO-2008-00117
: FFX-00104, Check Minimum Line Size to Allow the City Water Header to Provide the Aux.
: LO-IP3LO-2008-00144
: Feed Water Pumps with 800 GPM, Rev. 0
: LO-IP3LO-2008-00160
: FIX-00024,
: LO-IP3LO-2008-00172  
: CST-Level Setpoints, Channel Accuracies and Corresponding Volumes, Rev. 3
: FIX-00030, N2 Backup System Capacity to Support Critical AFW System Air Users in the Event of Loss of Instrument Air, Rev. 3
: FIX-00035, RHR Indicated Flow and Flow Errors for EOP, Rev. 0
: FIX-00145-00, Main Steam Pressure Loop Accuracy, Rev. 1
: FMX-00085, RWST Minimum Submergence Level, Rev. 1 
: Attachment
: FMX-00086, CST Critical Submergence at Varied Flow Rates, Rev. 1
: FMX-00130, Impact of Pipe Break Downstream of
: LCV-1158, Rev. 1
: FMX-00162, Establish Stroke Time for Valve
: LCV-1158, Rev. 0
: FMX-00237, Verification of Aux Feed Pump Full Flow Test Acceptance Criteria, Rev. 0
: FMX-000245, RHR Pump Available NPSH from Sump and RWST, Rev. 2
: FMX-00275, Pipe Flow Analysis for AFW System, Rev. 1
: FMX-00287, Verification of AF Pump Recirculation Flow Test Acceptance Criteria, Rev. 1
: FMX-00297, NPSH Calculation for RHR Pumps with One Pump/Heat Exchanger in Service, Rev. 2
: IP-CALC-04-00650, IP2 Aux Feedwater System Safety Valve Sizing
: MS-52, Rev. 0
: IP-CALC-04-01180, Attachment A, SQUG Panel Document, Rev. A
: IP-CALC-05-01034, Appendix R Cooldown Benchmark and Sensitivity Analysis Using
: RETRAN-3D, Rev. 1
: IP-CALC-06-00026, Indian Point Unit 2 (IP2) Hydraulic Analysis of Recirculation and Containment Sump Strainers, Rev. 3
: IP-CALC-06-00281, Ventilation System for EDG Building, Rev. 0
: IP-CALC-08-00022, Analysis of IP2 SBO/APPR DG Supplying IP2 SBO Loads, Rev. 0
: IP-RPT-08-00044, Study for the Impact of Bus Transfer Transients With 10-Cycle Dead-Time on the 480V Safety-Related Motor Performance for Indian Point 2 & 3, Rev. 0
: MEX-00131, Evaluation of Generic Letter 95-07 Power Operated Valves for Pressure Locking and Thermal Binding, Rev. 4
: PGI-00473, Motor Operated Valve Terminal Voltage; Altran Calculation No. 99621-C-002,
: Rev. 3
: PGI-00475,
: GL-89-10 MOV Protection - TOR Settings, Rev. 2
: PGI-00496, AOV System Calculation for STM
: GEN 21 Atmospheric Dump Valves
: PCV-1134,
: 1135, 1136, and 1137, Rev. 0
: PGI-00497, Auxiliary Feedwater System Air Operated Valve Functional and Maximum Expected Differential Pressure Calculation, Rev. 1
: PGI-00518, AOV Component Level Calculations for
: FCV-405A,
: FCV-405B,
: FCV-405C, and
: FCV-405D, Rev. 1
: SCN-00026,
: ESF-Safeguard Actuation Signal Response Time, Rev. 0
: SGX-00005, Emergency Diesel Generator Building Ventilation Upgrade, Rev. 0
: SGX-00007, 125V DC System Protection Device Coordination Study, Rev. 3
: SGX-00051, 6900V Switchgear Coordination Calculation for Switchgear Buses 1, 2, 3, 4, 5
and 6, Rev. 1
: SGX-00059, Safety Related 480V MCC Coordination Calculation for
: MCC-26A, Rev. 1
: SGX-00073, Bus Transfer (Transient) Analysis of the IP2 Electrical Distribution System, Rev. 1  
: SQUG Evaluation Sheet for EQID No. 0023EDJET, EDG No. 23 Jacket Water Expansion Tank dated 3/4/93 SQUG Evaluation Sheet for EQID No. PNL EPA77, EDG Vent Distribution Panel 1, dated 10/30/96 SQUG Evaluation Sheet for EQID No. PNL EPA78, EDG Vent Distribution Panel 2, dated 10/30/96 
: Attachment Completed Surveillance Test Procedures
: 2-PT-2M4, Safety Injection System Train "A" Actuation Logic and Master Relay Test, performed
: 5/18/09
: 2-PT-3Y010, Flow Test for Underground Service Water Line 409, performed 9/10/05
: 2-PT-M021A, Emergency Diesel Generator 21 Load Test, performed 4/1/09 & 5/28/09
: 2-PT-M021B, Emergency Diesel Generator 22 Load Test, performed 4/2/09 & 5/29/09
: 2-PT-M021C, Emergency Diesel Generator 23 Load Test, performed 3/31/09 & 5/28/09
: 2-PT-M110, Appendix R DG Functional Test, performed 1/17/09, 4/11/09 & 7/1/09
: 2-PT-Q013, Inservice Valve Tests, performed 4/23/09, 5/6/2009, 5/21/09 & 7/1/09
: 2-PT-Q013, Inservice Valve Tests -
: MOV 535 & 536 Data Sheets, performed 1/18/09
: 2-PT-Q013-DS250, Valve
: PCV-1136 IST Data Sheet, performed 4/17/08
: 2-PT-Q030A, 21 Component Cooling Water Pump, performed 3/18/09
: 2-PT-Q030B, 22 Component Cooling Water Pump, performed 5/12/09
: 2-PT-Q030C, 23 Component Cooling Water Pump, performed 4/16/09 & 7/9/09
: 2-PT-Q034, 22 Auxiliary Feed Pump, performed 4/23/09
: 2-PT-Q034A, 22 Auxiliary Feed Pump Steam Supply Valves, performed 6/12/09
: 2-PT-Q055, Pressurizer Pressure, performed 2/25/09 & 5/20/09
: 2-PT-Q058, Steam Generator Level Bistables, performed 3/18/09 & 6/11/09
: 2-PT-Q059, Containment Pressure Bistables, performed 3/10/09 & 6/5/09
: 2-PT-Q061, Main Steam Line Pressure Bistables, performed 1/27/09 & 4/23/09
: 2-PT-Q062, High Steam Flow and Turbine First Stage Pressure Bistables, performed 2/11/09 & 5/6/09 2-PT-Q063, Steam Flow/Feedwater Flow Mismatch Bistables, performed 1/6/09 & 3/31/09
: 2-PT-Q280A, 21 Residual Heat Removal Pump, performed 3/9/09 & 6/1/09
: 2-PT-Q280B, 22 Residual Heat Removal Pump, performed 3/26/09
: 2-PT-R013, Safety Injection System, performed 3/28/08
: 2-PT-R013B, Auxiliary Feedwater Pumps Automatic Actuation Circuitry, performed 3/27/08
: 2-PT-R014, Automatic Safety Injection System Electrical Load and Blackout Test, performed
: 4/22/06 & 3/28/08
: 2-PT-R022A, Steam Driven Auxiliary Feed Pump Full Flow, performed 3/21/08
: 2-PT-R062, Pressurizer PORVs, performed 4/10/08
: 2-PT-R083, AMSAC End-to-End Functional, performed 4/18/08
: 2-PT-R139, RHR Pumps, Flow Settings, and Check Valves, performed 3/29/08
: 2-PT-SA069, City Water Backup Cooling Flow Test, performed 11/13/06, 5/3/07, & 4/2/09
: 2-PT-V008A, 22 ABFPT Mechanical Overspeed Alternate Trip Test, performed 4/4/08
: 2-PT-V014, Overpressurization Protection System Analog Channels, performed 3/24/08
: 2-PT-V015, Overpressurization Protection System Logic Check, performed 3/24/08
: 2-PT-V024E, Main Steam Isolation Valves, performed 10/6/05, 3/18/08, & 4/19/08
: 2-PT-V064, Auto Transfer Verification of Offsite Power for 6.9KV Buses 2 and 3, performed
: 4/18/06 & 3/23/08
: 2-PT-W010, Weekly Battery Surveillance Requirement, performed 1/21/09 
: Attachment  
===Condition Reports===
===Condition Reports===
(Unit 3 unless denoted otherwise)  
(CR-IP2-)
: 2002-00141
: 1998-10046
: 2004-02269
: 2003-0860
: 2004-03663
: 2003-2511
: 2004-03859
: 2004-1445
: 2005-00956
: 2005-0772
: 2005-04058
: 2005-1401
: 2005-04071
: 2005-0374
: 2006-01003 
: 2005-3027
: 2006-01004
: 2005-3223
: 2006-01290
: 2005-3576
: 2006-01314
: 2005-3984
: 2006-01596 
: 2006-1970
: 2006-01917
: 2006-2020
: 2006-02071
: 2006-2256
: 2006-03241
: 2006-3224
: 2006-03557
: 2006-3691
: 2006-03559
: 2006-4678
: 2006-03867
: 2006-5017
: 2007-00018
: 2006-5208
: 2007-00089
: 2006-5241
: 2007-00275
: 2006-5422
: 2007-00286
: 2006-6511
: 2007-00295
: 2006-6867
: 2007-00518
: 2007-0219 2007-0980 2007-1046
: 2007-00556
: 2007-1442
: 2007-00655
: 2007-1779
: 2007-00682
: 2007-2189
: 2007-00699 
: 2007-3141
: 2007-00870
: 2007-3295
: 2007-00924
: 2007-3825
: 2007-00958
: 2007-4164
: 2007-00978 
: 2007-4174
: 2007-01003
: 2008-0002
: 2007-01030
: 2008-0668
: 2007-01049
: 2008-1021
: 2007-01129 
: 2008-1342
: 2007-01373
: 2008-1414
: 2007-01389
: 2008-1421
: 2007-01442
: 2008-1471
: 2007-01496
: 2008-1482
: 2007-01564
: 2008-2023
: 2007-01569
: 2008-2125
: 2007-01588
: 2008-2229
: 2007-01604 
: 2008-2447
: 2007-01620
: 2008-2710
: 2007-01629
: 2008-3264 2008-3476 2008-3869
: 2007-01640
: 2008-3889
: 2007-01641
: 2008-3901
: 2007-01713
: 2008-4230
: 2007-01808
: 2008-5047
: 2007-01834
: 2008-5212
: 2007-01844 
: 2008-5499
: 2007-01867
: 2009-0099
: 2007-01895
: 2009-0245
: 2007-01948
: 2009-0339
: 2007-02026 
: 2009-0340
: 2007-02030
: 2009-0341
: 2007-02047
: 2009-0346
: 2007-02111
: 2009-0462
: 2007-02123 
: 2009-0681
: 2007-02163
: 2009-0758
: 2007-02170
: 2009-0805
: 2007-02172
: 2009-0820
: 2007-02210 
: 2009-0868
: 2007-02213
: 2009-0978
: 2007-02224
: 2009-1245
: 2007-02272
: 2009-1473
: 2007-02351 
: 2009-2085 2009-2112 2009-2773*
: 2007-02417
: 2009-2796*
: 2007-02489
: 2009-2799*
: 2007-02527
: 2009-2824*
: 2007-02529 
: 2009-2828*
: 2007-02557
: 2009-2829*
: 2007-02616
: 2009-2838*
: 2007-02675
: 2009-2841
: 2007-02682
: 2009-2848*
: A-32007-02723
: 2009-2850*
: 2007-02774
: 2009-2857
: 2007-02826
: 2009-2858*
: 2007-02836
: 2009-2861*
: 2007-02868
: 2009-2862*
: 2007-02921
: 2009-2863*
: 2007-02939
: 2009-2865*
: 2007-02941 
: 2009-2866*
: 2007-02982
: 2009-2907
: 2007-03037
: 2009-2912*
: 2007-03065
: 2009-2917*
: 2007-03130 
: 2009-2945*
: 2007-03217
: 2009-2982
: 2007-03299
: 2009-2999* 2009-3006* 2009-3015*
: 2007-03317
: 2009-3016*
: 2007-03542 
: 2009-3017*
: 2007-03453
: 2009-3033*
: 2007-03499
: 2009-3036*
: 2007-03502
: 2009-3046*
: 2007-03535 
: 2009-3050*
: 2007-03560
: 2009-3065*
: 2007-03562
: 2009-3077*
: 2007-03577
: 2009-3081*
: 2007-03603 
: 2009-3083*
: 2007-03613
: 2009-3084*
: 2007-03637
: 2009-3085*
: 2007-03639
: 2009-3086*
: 2007-03646 
: 2009-3087*
: 2007-03660
: 2009-3091*  
: 2007-03730
: 2009-3142*  
: 2007-03751
: 2009-3143*  
: 2007-03753 
: 2009-3150*  
: 2007-03807
: 2009-3156*  
: 2007-03818
: 2009-3249*  
: 2007-03822
: 2009-3301*  
: 2007-03854 
  * CR written as a result of this inspection
: 2007-03869
: Design & Licensing Bases ConEdison Letter No.
: 2007-03869
: NL-81-136, Response to
: 2007-03900
: GL 81-14 Regarding Seismic Qualification of AFW System, dated 8/7/81 ConEdison Letter No.
: 2007-03957
: NL-85-A21, Response to NRC on Seismic Qualification of AFW Components, dated 2/4/85
: 2007-04002
: IP2-480V DBD, 480 Volt Electrical System Design Basis Document, Rev. 1
: 2007-04012
: IP2-AFW DBD, Auxiliary Feedwater System Design Basis Document, Rev. 1
: 2007-04024
: IP2-CCWS DBD, Component Cooling Water System Design Basis Document, Rev. 1
: 2007-04098 
: IP2-EDG DBD, Emergency Diesel Generator Design Basis Document, Rev.2
: 2007-04117
: IP2-ESF-DBD, Engineered Safeguards Features System Design Basis Document, Rev. 1
: 2007-04133
: IP2-MS DBD, Main Steam System Design Basis Document, Rev. 1
: 2007-04135
: IP2-RCS/SG DBD, Reactor Coolant System/Steam Generator Design Basis Document, Rev. 1
: 2007-04141 
: Letter from Murray Seiman, Consolidated Edison, to USNRC, Loss of RHR while the RCS is Partially Filled, dated 9/29/87 Letter from Stephen B. Bram to USNRC, Supplemental Response to NRC Bulletin 88-04 Potential Safety Related Pump Loss, dated 7/19/88
: 2007-04152
: NL-09-031, IPEC Letter to the NRC, Request for Exemption from 10
: 2007-04156
: CFR 50, Appendix R, Paragraph
: 2007-04174
: III.G.2 for Use of Operator Manual Actions for Indian Point Unit No. 2, dated 3/6/09 
: 2007-04193
: Attachment
: 2007-04204
: NRC Letter to Entergy Nuclear Operations, Indian Point Nuclear Generating Unit No. 2
: 2007-04210
: Issuance of Amendment RE: 3.26 Percent Power Uprate (TAC No. MC1865), dated 10/27/04
: 2007-04212
: Safety Evaluation Report, Susceptibility of Safety-Related Systems to Flooding from Failure of Non-Category I Systems for IP2, November 1980  
: 2007-04217
: 2007-04224
: 2007-04226
: 2007-04230
: 2007-04238
: 2007-04249
: 2007-04271
: 2007-04281
: 2007-04341
: 2007-04360
: 2007-04361
: 2007-04411
: 2007-04464
: 2007-04510
: 2007-04524
: 2008-00007
: 2008-00022
: 2008-00053
: 2008-00119
: 2008-00218
: 2008-00252
: 2008-00302
: 2008-00309
: 2008-00319
: 2008-00320
: 2008-00341
: 2008-00346
: 2008-00347
: 2008-00367
: 2008-00390
: 2008-00574
: 2008-00658
: 2008-00698 
: 2008-00748
: 2008-00753
: 2008-00753
: 2008-00767
: 2008-00818
: 2008-00819
: 2008-00953
: 2008-00961
: 2008-00978
: 2008-00984
: 2008-00987
: 2008-01081 
: 2008-01125
: 2008-01161
: 2008-01193
: 2008-01221 
: 2008-01236
: 2008-01241
: 2008-01245
: 2008-01248 
: 2008-01250
: 2008-01257
: 2008-01286
: 2008-01334 
: 2008-01347
: 2008-01436
: 2008-01437
: 2008-01446
: 2008-01446
: 2008-01538
: 2008-01589
: 2008-01594 
: 2008-01599
: 2008-01617
: 2008-01717
: 2008-01717 
: 2008-01835
: 2008-01837
: 2008-01863
: 2008-01951 
: 2008-01995
: 2008-02000
: 2008-02008
: 2008-02195 
: 2008-02223
: 2008-02252
: 2008-02280
: 2008-02291 
: 2008-02312
: 2008-02337
: 2008-02358
: 2008-02398 
: 2008-02416
: 2008-02495
: 2008-02527
: 2008-02601
: 2008-02636
: 2008-02798
: 2008-02832
: 2008-02893
: 2008-02894
: 2008-02897
: 2008-02933
: 2008-02952
: 2008-02979
: 2008-03029
: 2008-03041
: 2008-03069
: 2008-03073
: 2008-03085
: 2008-03133
: 2008-03138
: 2008-03154
: 2008-03204
: 2008-03204
: 2008-03207
: 2008-03208
: 2008-03216
: 2008-03234
: 2009-00011
: 2009-00022
: 2009-00052
: 2009-00067
: 2009-00119 
: 2009-00134
: 2009-00139
: 2009-00213
: 2009-00213 
: 2009-00275
: 2009-00314
: 2009-00323
: 2009-00329 
: 2009-00342
: 2009-00354
: 2009-00393
: 2009-00405 
: 2009-00466
: 2009-00475
: 2009-00573
: 2009-00615 
: 2009-00719
: 2009-00816
: 2009-00925
: 2009-01071
: A-42009-01156
: 2009-01190
: 2009-01191
: 2009-01245
: 2009-01299
: 2009-01379
: 2009-01384
: 2009-01392 
: 2009-01406
: 2009-01406
: 2009-01412
: 2009-01474 
: 2009-01585
: 2009-01587
: 2009-01649
: 2009-01651 
: 2009-01677
: 2009-01749
: 2009-01806
: 2009-01884 
: 2009-01886
: 2009-01896
: 2009-01916
: 2009-01998 
: 2009-02016
: 2009-02251
: 2009-02268
: 2009-02336 
: 2009-02481
: 2009-02485
: 2009-02542
: 2009-02553 
: 2009-02569
 
*2009-02559  *2009-02573  *2009-02576  *2009-02580
*2009-02587  *2009-02589  *2009-02591  *2009-02593
*2009-02596  *2009-02599  *2009-02606  *2009-02607
*2009-02608  *2009-02609  *2009-02648  *2009-02657
*2009-02662  *2009-02664  *2009-02667  *2009-02668
*2009-02676  *2009-02686  *2009-02691  *2009-02692
*2009-02709  *2009-02716
 
  *NRC Identified During Inspection
: Operating Experience
: IN 2006-02, Use of Galvanized Supports and Cable Trays with Meggitt Si 2400 Stainless-Steel-Jacketed Electrical Cables
: IN 2006-22, New Ultra-low-sulfur Diesel Fuel Oil Could Adversely Impact Diesel Engine Performance
: IN 2008-02, Findings Identified During Component Design Bases Inspections
: IN 2008-09, Turbine-driven Auxiliary Feedwater Pump Bearing Issues
: IN 2008-11, Service Water System Degradation at Brunswick Steam Electric Plant Unit 1
: IN 2009-02, Biodiesel In Fuel Oil Could Adversely Impact Diesel Engine Performance
: IN 2009-04, Age-Related Constant Support Degradation
: RIS 08-14, Use of Tormis Computer Code for Assessment of Tornado Missile Protection
: IN 2007-28, Potential Common Cause Vulnerabilities in Essential Service Water Systems Due To Inadequate Chemistry Controls
: IN 2007-29, Temporary Scaffolding Affects Operability of Safety-Related Equipment
: OE 28835
: OE 28836
: OE 28837
: OE 28838
: OE 28840
: OE 28841
: OE 28843
: OE 28845  
===Drawings===
===Drawings===
: 21-LL-31173, Schematic Diagram 480V Switchgear 31, sheet 6, Rev. 25
: 179950, Copes-Vulcan Model D-100, 6 Inch, Class 6000 Valve Assembly Tandem Trim 3
: 21-LL-31173, Schematic Diagram 480V Switchgear 31, sheet 7, Rev. 11  
rd Generation, Rev. 4
: 21-LL-31173, Schematic Diagram 480V Switchgear 31, sheet 6B, Rev. 4
: 193183, Unit 1 Piping Flow Diagram City Water System, Rev. 29
: 21-F-27513, Auxiliary Coolant System, Rev. 30
: 208485, 28 Inch OD Pipe Main Steam Stop Valve, Rev. 8
: A-5Calculations
: 2688, Flow Diagram Instrument Air Containment Building & Auxiliary Boiler Feed Pump;
: IP3-CALC-PABHV-01419, PAB Appendix R Heat-Up Analysis, Rev. 0
: Building, Rev. 27
: IP3-CALC-PABHV-02003, RHR Room Heat-Up Calculation, Rev. 0
: 251132, AFW Flow Control Loop, Rev. 6
: IP3-CALC-HVAC-02073, Electrical Load Analysis per
: 251231, AFW Steam Supply to Auxiliary Feed Water Pump 22, Rev. 5
: ENG-560, Rev. 0
: 2422, CVCS Loop Diagram for RCP Instrumentation, Rev. 3
: PGI-00419-00, Indian Point Unit 2 Primary Auxiliary Building Room Heat Analyses,
: 263935, 125VDC Power Panel #21 Circuit Assignment, Rev. 0
: December 1999 
: 263936, 125VDC Power Panel #22 Circuit Assignments, Rev. 1
: Non-Cited Violations and Findings
: 306641-01, W/D of Temperature Controller in Station Service Transformer #5, Rev. 1
: NCV 05000286/2007004-01, Failure to monitor emergency lighting system in accordance with 10CFR 50.65 (a)(1) action plan
: 311906,
: NCV 05000286/2007005-01, Failure to provide an adequate EDG maintenance procedure
: SOV 455C Pressurizer PORV
: NCV 05000286/2007006-01, Inadequate pressure locking methodology used to ensure valve operability
: PCV-455C, Rev. 1
: NCV 05000286/2007006-03, Non-conservative calculation for TDAFW pump discharge pressure used for surveillance testing
: 311907,
: NCV 05000286/2007006-06, Inadequate design inputs and testing requirements for EDG loading
: SOV 456 Pressurizer PORV
: NCV 05000286/2008002-04, Failure to maintain EDG jacket cooling water pressure switch design control
: PCV-456, Rev. 1
: NCV 05000286/2008004-02,
: 360858, Copes-Vulcan Series D-1000 Valve Assembly Class 900, Rev. 0
: Failure to follow maintenance procedures results in degraded EDG for 37 days
: 400882, Station Blackout and Appendix R Diesel Generator Set P&ID Diesel Cooling Water System Mechanical, Rev. 0
: NCV 05000286/2008004-01, Failure to follow procedures results in the inadvertent start of two  auxiliary boiler feed pumps at power
: 709091 Sh. 1, Auxiliary Feedwater Control Globe Valve, Rev. 1
: NCV 05000286/2008010-01, Inadequate design control of internal recirculation pumps  
: 21-F-2017 Sh. 2, Flow Diagram Main Steam, Rev. 84
: 21-F-2018, Flow Diagram Condensate and Boiler Feed Pump Suction, Rev. 143
: 21-F-2019, Flow Diagram Boiler Feedwater, Rev. 114
: 21-F-2028, Flow Diagram Jacket Water to Diesel Generator, Rev. 36
: 21-F-2030, Flow Diagram Fuel Oil to Diesel Generator, Rev. 39
: 21-F-2036, Flow Diagram Instrument Air Control Building Conventional Plant, Rev. 98
: 21-F-2593, PAB Composite Piping at Charging Pumps, Rev. 40
: 21-F-2696, PAB Service Air, City Water & Drains, Rev. 35
: 21-F-2720, Flow Diagram Auxiliary Coolant System, Rev. 89
: 21-F-2729, SG Blowdown & Blowdown Sample System Flow Diagram, Rev. 69
: 21-F-2736, UFSAR Figure 9.2-1 SHT 1 - CVCS Flow Diagram, Rev. 128
: 21-F-3006, Single Line Diagram 480V MCC26A and 26B, Rev. 94 & 95
: 21-F-3204, 125 VDC Power Panels 21 & 22 Wiring Diagram, Rev. 76
: 21-LL-3113 Sh. 1, Schematic Diagram - 6900V Switchgear 21, Rev. 14
: 21-LL-3113 Sh. 3, Schematic Diagram - Breaker 52/UT1-ST5 Bus #1 Tie, Rev. 14
: 21-LL-3113 Sh. 4, Schematic Diagram - Breaker 52/UT2 Bus 2, Rev. 10
: 21-LL-3113 Sh. 5, Schematic Diagram - Breaker 52/UT2-ST5 Bus 2-5 Tie, Rev. 10
: 21-LL-3113 Sh. 7, Schematic Diagram - Breaker 52/RCP21 Reactor Coolant Pump 21, Rev. 16 9321-LL-3113-10 Sh. 16, Schematic Diagram - 6900V Bus 1,2, & 5 Lockout Relays
(86/UT1, 86/UT2, & 86/ST5), Rev. 10
: 21-LL-3130 Sh. 5, Generator Primary Lockout Relay 86P, Rev. 31  
: 21-LL-3130 Sh. 6, Generator Backup Lockout Relay 86BU, Rev. 38 
: Attachment
: 21-LL-3131 Sh. 8, AFW Logic Schematic, Rev. 10
: 21-LL-3132 Sh. 5, Schematic Diagram - Pilot Wire and Misc. Lock-Out Relays, Rev. 11  
: 21-LL-3601 Sh. 3, Feedwater Bypass Valves Schematic, Rev. 10
: 21-LL-3601 Sh. 17, Feedwater Bypass Valves Schematic, Rev. 12
: A207698, Lube Oil for Diesel Generators, Rev. 26
: A208088, One Line Diagram 480VAC Swgrs. 21 & 22, Bus 2A, 3A, 5A & 6A, Rev. 43
: A208168, UFSAR Figure 9.2-1 SHT 2 - CVCS Flow Diagram, Rev. 53
: A208377, Main One Line Diagram, Rev. 12
: A208500, One Line Diagram for 480VAC
: MCC-26AA and MCC26BB &120VAC Distribution Panels 1&2, Rev. 45 A225016, Safeguards Actuation Schemes - Train A, Rev. 12
: A225018, Safeguards Actuation Schemes - Train B, Rev. 10
: A225096, Turbine Trip Signals Logic Diagram, Rev. 19
: A225097, 6900V Bus Auto Transfer Logic Diagram, Rev. 5
: A225101, Safeguards Sequence Logic Diagram, Rev. 11
: A225102, Pressurizer Trip Signals Logic Diagram, Rev. 5
: A225105, Safeguards Actuation Signals Logic Diagram, Rev. 10
: A225106, Feedwater Isolation Logic Diagram, Rev. 7
: A227781, Flow Diagram - Auxiliary Coolant System, Rev. 81
: A231592, 6900 Volt AC One Line Diagram, Rev. 19
: A235296, Flow Diagram Safety Injection System, Rev. 69
: A250907, Electrical Transmission and Distribution System, Rev. 21
: A251783, Flow Diagram Auxiliary Coolant System Residual Heat Removal System, Rev. 29
: AAA00738, 45 Actuator 2 Body, 657 HPT Diaphragm Actuated Control Valve for
: FCV-405A, 405B, 405C, and 405D, Rev. A B192505 Sh. 1, Piping Flow Diagram City Water System, Rev. 19
: B192506 Sh. 2, Piping Flow Diagram City Water System, Rev. 40
: B243683, Diesel Generator Ventilation System Details, Rev. 3
: D252276, SIS Recirculation Flow Loop #640, #946, Rev. 5
: IP2-S-000209, Pressurizer Power Relief Line Block Valve 535, Rev. 8
: IP2-S-000210, Pressurizer Power Relief Line Block Valve 536, Rev. 8
: IP2-S-000231, One-Line Schematic for EDG Building Ventilation Dist. Panels #1 & #2, Rev. 4
: IP2-S-000291, EDG Exhaust Fan #318, Rev. 3
: IP2-S-000346, Install of 6
th EDG Exh Fan - Swd, Rev. 2
: Engineering Evaluations
: 04-001147, Procurement Engineering Technical Evaluation, Rev. 3
: CR-IP2-2006-03691
: CA-00002, Emergency Diesel Generator No. 21 Failed
: PT-M21A Apparent; Cause Evaluation, dated 7/19/06
: CR-IP2-2009-0978, Operability Evaluation for
: PCV-1136, dated 3/12/09
: CR-IP2-2008-1021, Apparent Cause Evaluation for MSIV
: MS-1-22, dated 3/24/08
: EEN-04-0108, Item Equivalency Evaluation, Rev. 4
: FMA07P0520, Failure Mode Analysis Report of Non-Safety Related Foxboro Power Supply for Entergy Nuclear Northeast - Indian Point 2, dated 3/13/07 
: Attachment
: IP-RPT-06-00022, Model 93 RCP Buffer Volume Related to Safe Shutdown Analysis, Rev. 0  
: Technical Report No. 00263-TR-001, Functionality and Risk Significance Evaluation of the Indian Point Unit 1 and 2 Mechanical and Electrical Systems Located in the Utility Tunnel, dated March 2001
: Technical Report No. 92155-TR-01, Structural Assessment of 600,000 Gallon Condensate
: Storage Tank, September 1992
: Maintenance Work Orders
: 00126023
: 00141067
: 00141663
: 00145034
: 00148522
: 00152728
: 00171798
: 01-22289
: 2-21968
: 2-31082
: 2-32011 02-32013 02-33308
: 03-11725
: 03-31379
: 03-31474
: 03-31478
: 06-23642
: 251428
: 287272
: 295645
: 296260
: 51311792
: 51319252
: 51323098
: 51557019
: 51567240
: 51679124
: 51681055
: 51686249
: 51692345
: 51697357
: 2037044
: IP2-01-22271
: IP2-03-20310
: IP2-03-25125
: IP2-03-25169
: IP2-03-25176
: IP2-04-17932
: IP2-04-31352
: IP2-04-32996
: IP2-06-18008
===Miscellaneous===
: 16" City Water Pipe - Flow Test, performed 5/26/09
: 1P-RPT-05-00138, IPEC Unit 2 and Unit 3 AOV Scoping and Categorization Report, Rev. 0
: ANSI C50.41-2000, American National Standard for Polyphase Induction Motors for Power Generating Stations to
: IPP-98-526, Draft Uncertainties for RHR and Containment Recirculation Flow Functions, February 1998
: CCW Certified No. 22 Pump Curve, IR No. N-1402, dated 2/15/91
: ConEdison Order No.
: 4900092, Performance & Thrust Test Report 8x20 W, Ingersoll-Dresser Pump Co., dated 1/20/95
: CR-HQN-2007-00521
: Cummins Metropower Inc. Letter, Quote No. 2004044b, IP2 SBO and Appendix R 
: Diesel Generator Set, dated 05/14/04
: DRN-04-02623, Procedure 2-PT-Q030C change from Rev. 9 to Rev. 10, dated 9/8/04
: EC No.
: 5000034211, RHR Pump Room Flooding, September 2008
: ENN-EE-S-010-IP2, Electrical Separation Design Criteria, Rev. 2
: ENS-I&C-DC, Power Supply PM Basis Template, Rev. 2
: EPRI
: EL-4286, Improved Motors for Utility Applications Volume 2: Bus Transfer Studies, October 1986
: EPRI
: NP-7412R1s, EPRI Air-Operated Valve Maintenance Guide, dated 11/96
: Ingersoll-Dresser Pumps, Pump 8 x 20w, Residual Heat Removal Pump Curve, dated 11/23/94
: IP2-05-13447, Replace Westinghouse Type REH Breakers in DPBL 22, Rev. 0
: IP2-9412, Operations Document Feedback Form for 2-PT-M110, dated 7/28/09
: IP2-9437, Operations Document Feedback Form for EOP E-3 Step 2, dated 8/12/09
: IP2-UT-09-036, 180 Day Follow-up Exam of various SW Piping Weld Leaks, dated 8/7/09
: IR-RPT-04-00230, Internal Flooding Analysis Notebook, Appendix C, Rev. 1
: LER 2007-004-00, Manual Reactor Trip Due to Decreasing Steam Generator Levels Caused by Loss of Feedwater Flow as a Result of Feedwater Pump Suction Pressure Transmitter Power Supply Failure, dated 4/30/07 
: Attachment Letter from R. Laubham, Westinghouse, to Dave Morris, Entergy, Condensate Storage Tank Minimum Usable Inventory, dated 6/16/04 Log Entries Report, dated 7/10/09 - 7/20/09
: LO-NOE-2005-01008
: LO-NOE-2007-00427
: Maintenance Rule Basis Document City Water System (CYW), Rev. 2
: MPR Associates Trip Report, Support AVR Card Inspection Following Part 21 Notice for EDG 
: 31, 32 and 33, dated 3/17/09, 3/27/09, & 4/13/09
: MPR Report No. 1051, Report of Operability Tests of RHR Pumps at Reduced Reactor Coolant System Levels, February 1988
: N-1402, Component Cooling Water Pump Curve, dated 02/20/81
: NL-85-286-C01, NRC Commitment Regarding AFW Seismic Qualification, dated 12/26/85
: NL-85-286-C02, NRC Commitment Regarding AFW Seismic Qualification, dated 12/26/85
: RHR Certified No. 22 Pump Curve, IR No. 4688, dated 5/12/67
: Rover Rounds, dated 7/9/09 - 7/19/09
: TDAFW Certified No. 22 Pump Curve, Worthington No. E-216435, dated 4/22/87
: Top Ten Action Plan - IPEC Power Supply PMs, Rev. 4
: Westinghouse Letter
: SEE-00-157, IP2 Restart Assessment-RHR Pump NPSH Evaluation
: During Recirculation, dated 12/20/00 Westinghouse Letter
: SEE-03-73, Rev. 1, Indian Point Unit 2-Stretch Power Uprate Project Report for NSSS Systems, dated 11/26/03
: Westinghouse Report No.
: WCAP-12312, Safety Evaluation for an Ultimate Heat Sink Temperature of 95º F at Indian Point Unit 2, January 2004
: WOG ERG LE3, Steam Generator Tube Rupture,
: LP-Rev. 2
: Normal and Special (Abnormal) Operations Procedures
: 2-AOP-CCW-1, Loss of Component Cooling Water, Rev. 1
: 2-AOP-CVCS-1, Chemical and Volume Control System Malfunctions, Rev. 5
: 2-AOP-RCP-1, Reactor Coolant Pump Malfunction, Rev. 8
: 2-AOP-SSD-1, Att. 10, Backup Cooling Water Supply to Charging Pumps, Rev. 13
: 2-ARP-003, Diesel Generator, Rev. 3
: 2-ARP-SCF 2-3, Condensate Storage Tank Low Level, Rev. 41
: 2-ARP-SFF 3-5, RCP Thermal Barrier Low Delta-P, Rev. 26
: 2-ARP-SHF (2-10), 6900 V Bus Transfer Block, Rev. 29
: 2-ARP-SHF (4-7), Motor Control Center 26A, 26B and 26C - 52/MCC 26A-26B-26C Auto Trip, Rev. 29
: 2-E-0, Reactor Trip or Safety Injection, Rev. 1
: 2-E-0 BG, Reactor Trip or Safety Injection Background Document, Rev. 0
: 2-E-1, Loss of Reactor or Secondary Coolant, Rev. 0
: 2-E-1 BG, Loss of Reactor or Secondary Coolant Background Document, Rev. 0
: 2-E-3, Steam Generator Tube Rupture, Rev. 0
: 2-E-3 BG, Steam Generator Tube Rupture Background Document, Rev. 0
: 2-E-3 DEV, E-3 EOP Deviation Document, Rev. 0
: 2-ECA-1.1, Loss of Emergency Coolant Recirculation, Rev. 0
: 2-ES-0.1, Reactor Trip Response, Rev. 2
: 2-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 2
: 2-FR-C.1, Response to Inadequate Core Cooling, Rev. 0
: 2-FR-C.1 BG, Response to Inadequate Core Cooling Background Document, Rev. 0 
: Attachment
: 2-FR-H.1, Response to Loss of Secondary Heat Sink, Rev. 3
: 2-FR-H.1 BG, Response to Loss of Secondary Heat Sink Background Document, Rev. 0
: 2-SOP-1.4.1, Overpressure Protective System (OPS) Operation, Rev. 19
: 2-SOP-4.1.2, Component Cooling System operation, Rev. 35
: 2-SOP-4.2.2, Operation With Reduced RCS Inventory, Rev. 20
: 2-SOP-27.1.4, 6900 Volt System, Rev. 27
: 2-SOP-27.3.1.1, 21 Emergency Diesel Generator Manual Operation, Rev. 19
: SOP 27.3.2, Filling Diesel Fuel Oil Storage, Rev. 21
: 2-SOP-27.6, Appendix-R Diesel Generator Operation, Rev. 6
: 2-SOP-AFW-002, Auxiliary Feedwater System Support Procedure, Rev. 1
: 2-SOP-ESP-001, Local Equipment Operation and Contingency Actions, Rev. 4 
===Operating Experience===
: LO-NOE-2007-00078, IP2 Review of NRC
: IN 2007-06, dated 4/30/07
: NRC Information Notice 92-29, Potential Breaker Miscoordination Caused By Instantaneous
: Trip Circuitry, dated 4/17/92
: NRC Information Notice 94-33: Capacitor Failure in Westinghouse Eagle 21 Plant Protection Systems, dated 5/9/94
: NRC Information Notice 98-43, Leaks in the Emergency Diesel Generator Lubricating Oil and
: Jacket Cooling Water Piping, dated 12/4/98
: NRC Information Notice 2005-14, Loss of Seal Cooling to Westinghouse RCPs, dated 6/1/05 NRC Information Notice 2005-30, Safe Shutdown Potentially Challenged by Unanalyzed Internal Flooding Events and Inadequate Design, dated 11/7/05 NRC Information Notice 2008-09, Turbine-Driven AFW Pump Bearing Issues, dated 5/22/2008
: NRC Information Notice 2007-06, Potential Common Cause Vulnerabilities in Essential Service Water Systems, dated 2/9/07 NRC Information Notice 2009-02, Biodiesel in Fuel Oil Could Adversely Impact Diesel Engine Performance, dated 2/23/09
: NRC Information Notice 2009-10, Transformer Failures - Recent Operating Experience, dated 7/7/09 Westinghouse
: TB-04-22, RCP Seal Performance, Rev. 1
: Westinghouse
: WCAP-16755P, Operator Time Critical Action Program Standard, Rev. 0
: Operator Training
: I2SG-LOR-EOP009, Response to SGTR, E-3, and
: ES-3 Lesson Plan, Rev. 1
: JPM 0590080404, Replace 21 Feedwater Regulating Valve Air Lines for Local Operation, dated 8/22/07
: JPM 0060020404, Establish Backup Cooling to SI Pumps, dated 3/1/06
: JPM 0060020404, Lineup City Water to SI and RHR Pumps with Pumps Running, dated 3/1/06
: JPM 0840010402, Establish Backup Cooling to Charging Pumps, dated 3/1/06
: JPM 0840041624-1, Lineup City Water to SI and RHR Pumps with Pumps Shutdown, dated 3/1/06
: LEQ-SES-35, Steam Generator Tube Rupture Simulator Scenario, Rev. 1 
: Attachment Preventive Maintenance
: 0-ELC-403-BUS, Inspection and Cleaning of 480 Volt Bus Duct, performed 11/7/04 & 4/5/08
: 0-GNR-403-ELC, Emergency Diesel Generator Quarterly Inspection, performed 7/21/09
: 0-LUB-401-GEN, Lubrication of Plant Equipment, performed 1/29/09 0-VLV-404-AOV, Use of Air Operated Valve Diagnostics, performed 11/1/04, 11/13/04, 11/18/04,  & 2/25/09 0-VLV-415-VCK, Main Steam Valve Overhaul and Replacement, performed 4/11/08
: 3-IC-PC-I-Y-1103, Auxiliary Feed Pump No. 32 Tachometer, performed 11/5/08
: 51768428-01, 3M Insp Xfmr Station Service Transformer 5A Clg Sys, Clean and Manual Test Fans, performed 11/3/06 & 3/9/09
: 2027372-01, 3M Insp Xfmr Station Service Transformer 5A Clg Sys, Clean and Manual Test Fans, performed 3/9/09
: AOV-B-011-A, Copes Vulcan Air Operated Atmospheric Steam Dump Valves Maintenance Procedure, performed 11/14/04 & 11/13/04
: IP2-02-61376, 4Y Cal 6.9kV Bus Section 5, SST5 Relay, performed 11/6/06
: IP2-04-24880, 2-BRK-023-ELC and 2-BRK-024-ELC for Breaker 52/6B, performed 3/18/06 &  
: 3/20/06
: IP2-05-13447, Replace Westinghouse Type REH Breakers in DPBL 22, performed 5/4/06
: O-EDG-407-ELC, Emergency and Appendix "R" Diesel Generator Engine Analysis/Inspection, performed 7/21/09
: PMS-B-002-A, Worthington (#22) Auxiliary Boiler Feed Pump Turbine 10 Year Dismantle Inspection, performed 9/24/02
: VMS-B-002-A, Valve Repacking Using Graphite Packing and/or Live Load, performed 11/12/04  
===Procedures===
===Procedures===
: EN-DC-128, Fire Protection Program Review, Rev. 3
: 0-BKR-406-ELC, Westinghouse 6900 Volt Breaker Inspection and Cleaning, Rev. 11
: EN-DC-205, Maintenance Rule Monitoring, Rev. 2
: 0-PNL-401-ELC, Distribution Panel and Breaker Maintenance and Inspection, Rev. 3  
: EN-DC-206, Maintenance Rule (a)(1) Process, Rev. 1
: 0-TUR-403-AFP, Worthington Auxiliary Boiler Feed Pump Turbine Preventive Maintenance, Rev. 4 0-VLV-403-AOV, Copes-Vulcan Model D-100 and D-1000 Air Operated Valves with Quick Change Trim, Rev. 1
: EN-EC-100, Guidelines for the Implementation of the Employees Concern Program, Rev. 4
: 0-XFR-401-ELC, Station Service and Load Center Transformers Outage Inspection, Rev. 0
: EN-HU-101, Human Performance Program, Rev. 6
: 2-ARP-SCF, Condensate and Boiler Feed, Rev. 41
: EN-HU-103, Human Performance Error Reviews, Rev. 1
: 2-BRK-023-ELC, DB Breaker Amptector/Westector Overcurrent Test, Rev. 4
: EN-LI-100, Process Applicability Determination, Rev. 7
: 2-BRK-024-ELC, DB Breaker Amptector/Westector Calibration Test, Rev. 1  
: 2-COL-29.2, Instrument Air System, Rev. 29
: 2-MCC-001-ELC, Westinghouse Type W-480 Volt Motor Control Center Preventive Maintenance, Rev. 3
: 2-PT-M110, Appendix R DG Functional Test, Rev. 2
: EN-DC-140, Air operated Valve Program, Rev. 1
: EN-LI-102, Corrective Action Process, Rev. 13
: EN-LI-102, Corrective Action Process, Rev. 13
: EN-LI-104, Self-Assessment and Benchmark Process, Rev. 4
: MS-104, IP Unit #2 Maintenance Standard Inspection and Cleaning of Bus Bars, Contacts, Ground Connections, Wiring and Insulators, Rev. 2
: EN-LI-114, Performance Indicator Process, Rev. 4
: OAP-008, Severe Weather Preparations, Rev. 6
: EN-LI-118, Root Cause Analysis Process, Rev. 9
: OAP-012, EOP Users Guide, Rev. 5
: EN-LI-119, Apparent Cause Evaluation (ACE) Process, Rev. 8
: OAP-017, Plant Surveillance and Operator Rounds, Rev. 6
: EN-LI-121, Entergy Trending Process, Rev. 8
: OAP-038, Operations Mechanical Equipment Operating Guidelines, Rev. 3  
: EN-MA-101, Conduct of Maintenance, Rev. 6
: Attachment
: EN-OE-100, Operating Experience Program, Rev. 6
: OAP-115 Att. 5, Time Critical Operator Actions, Rev. 9
: EN-OP-102, "Protective and Caution Tagging," Rev. 3
: PT-Q13, Inservice Valve Test Data Sheet No. 94, Rev. 23
: EN-OP-104, Operability Determinations, Rev. 3
: PT-R35, Inservice Valve Tests, Rev. 11
: EN-OP-115, Conduct of Operations, Rev. 6
: SEP-SW-001,
: A-6EN-QV-108, QA Surveillance Process, Rev. 6
: GL 89-13 Service Water Program, Rev. 1
: EN-WM-100, Work Request Generation, Screening and Classification, Rev. 3
: Risk and Margin Management
: 3-SOP-ESP-001, Local Equipment Operation and Contingency Actions, Rev. 19
: IP-RPT-04-00230, Indian Point Unit Two Probabilistic Safety Assessment (PSA), Rev. 1
: 3-SOP-INST-001, Filling, Venting and Flushing of Instrumentation Impulse Lines, Rev. 19
: IP-RPT-04-00230 App. H, Human Reliability Analysis, Rev. 1
: 3-COL-RW-2, Service Water System, Rev. 42
: PD-95-034, Individual Plant Examination of External Events for Indian Point 2, December 1995
: 3-SYS-018-GEN, Installation, Control and Removal for Support Electrical and Mechanical Equipment Required for Scheduled Bus 2A Outages, Rev. 1 3-SOP-SI-001, Safety Injection System Operation, Rev. 44
: Risk-Informed Inspection Notebook for Indian Point Nuclear Generating Station, Rev. 2.1a
: 3-SOP-CC-001B, Component Cooling System Operation, Rev. 33
: System Health Reports & Trending
: 3-SOP-INST-001, Filling, Venting and Flushing of Instrumentation Impulse Lines, Rev. 19
: AFP Turbine Outboard and Inboard Bearing Lube Oil Samples, 2004-2008
: Surveillance Procedures 
: 6.9kV System Health Report, 1st Quarter 2009
: 3-PT-M62A, 480V Undervoltage/Degraded Grid Protection System Bus 2A and 3A Functional, Rev. 7 3-PT-Q001A, #31 Station Battery Surveillance, Rev. 6
: 480V System Health Report, 1st Quarter 2009
: 3-PT-Q001B, #32 Station Battery Surveillance, Rev. 6
: AFW System Health Report, 1st Quarter 2009
: 3-PT-Q001C, #33 Station Battery Surveillance, Rev. 8
: AOV Program Health Report, 2nd Quarter 2009
: 3-PT-Q001D, 34 Station Battery Surveillance, Rev. 5
: CCW System Health Report, 1st Quarter 2009
: 3-PT-Q01A, 31 Station Battery Surveillance, Rev. 4
: EDG System Health Report, 1st Quarter 2009
: 3-PT-Q01B, 32 Station Battery Surveillance, Rev. 5
: Engineered Safeguards Initiation Logic System Health Report, 1st Quarter 2009
: 3-PT-Q01D, 34 Station Battery Surveillance, Rev. 4
: IP-2 Reliability - CYW System, dated August 2007 - June 2009
: 3-PT-R156A, Station Battery #31 Load Profile Service Test, Rev. 12
: Main Steam System Health Report, 1st Quarter 2009
: 3-PT-R172D, Station Battery #34 Modified Performance Test, Rev. 7
: RHR System Health Report, 1st Quarter 2009
: 3-PT-Q092B, 32 Service Water Pump Train Operational Test, Rev. 10
: Service Water NDE RT & UT Test Results Report for Zurn Strainer Pit, 1992 to July 2009
: 3-PT-W013, Station Battery Visual Inspection, Rev. 22
: Station Diesels Annual Health Report, 2007 & 2008
: 3-PT-R-152, Operability Testing of Safe Shutdown Equipment," Rev. 8
: Vendor Technical Manuals
: 3-PT-W001, Emergency Diesel Support Systems Inspection," Rev. 40
: 01:P13:37, Instruction Manual for Diaphragm Operated Copes-Vulcan Control Valves, Rev. 4
: 3-PT-R090D, Emergency Local Operation of Auxiliary Boiler Feedpumps," Rev. 13
: 1766, Atwood & Morrill Instruction Manual Main Steam Isolation and Main System Check Valves, Rev.2
: 3-PT-Q129, Service Water System Alignment Verification, Rev. 5
: 2404, Copes Vulcan,
: 3-PT-R177, Pressurizer Heater Output and Backup Heater Groups 31, 32, and 33 Local Operation Test, Rev. 4 3-PT-R066A, IST of Check Valves
: PCV-1139 Installation, Operation & Maintenance Instruction, Rev. 0
: AC-741, 738A+B;
: 22, Westinghouse Air Circuit Breaker Type DH, Rev. n/a
: SI-838A, B, C, D; and
: I.B.
: SI-897A, B, C, D, Rev. 6 3-PT-R066, IST of Check Valves
: WCR-5815, Westinghouse Instruction Book Type ASL Core Form Power Center Transformer, S.O. 24-Y-4800-1, dated 10/67 Westinghouse Transformers Test Report (for Station Service Transformer #5), dated 10/26/67
: SI-881;
: Worthington Manual No. W-9C, Worthington Single Stage Steam Turbine Instructions, Rev. 2  
: AC-741, 738A+B;
: Attachment
: SI-838A, B, C, D; and
: SI-897A, B, C, D, Rev. 11 3-PT-R-152, Operability Testing of Safe Shutdown Equipment, Rev. 8
: 3-PT-R090D, Emergency Local Operation of Auxiliary Boiler Feed Pumps, Rev. 13
: 3-PT-R090E, 32 Auxiliary Boiler Feedwater Pump Local Operation Verification Test, Rev. 12
: 3-PT-R177, Pressurizer Heater Output and Backup Heater Groups 31, 32, and 33 Local Operation Test, Rev. 4
===Work Orders===
: 00109881
: 00103831
: 00126328
: 00186510
: 00188706
: 00196662
: 51325013
: 51325014
: 51476675
: 51478702
: 51478703
: 51478701
: A-751465253
: 51556617
: 51565142
: 52039046
: 52040305
: 52186684
: 52188481
===Miscellaneous===
: IP3-RPT-ESS-01885, "Maintenance Rule Basis Document
: IP3-RPT-ESS-01885 for System D11-0066 Engineered Safeguards Initiation Logic System," Rev. 1
: IP3-DBD-307, "480V AC Electrical Distribution System," Rev. 3
: Operation Decision-Making Issue "31 and 32 Battery Cover Cracks," Rev. 4 Safety Evaluation by the Office of Nuclear Reactor Regulation Related to Amendment No. 54 to Facility Operating License No.
: DPR-64 Power Authority of the State of New York Indian Point Nuclear Generating Unit No. 3 Docket No. 50-286, dated April 9, 1985 Letter from "Indian Point Units 2 and 3 Docket Nos. 50-247 & 50-286
: NL-05-053" to "U.S. Nuclear Regulatory Commission" regarding "Proposed Change to Technical Specifications Regarding Trip Actuating Device Surveillance Requirements for Setpoint Verification" dated April 22, 2004
: IP3-RPT-IA-01891, "Instrument Air and Instrument Air Closed Cooling Systems Maintenance Rule Basis Document," Rev. 0 Maintenance Rule Expert Panel Meeting Minutes, 10/30/2008
: IP3 Instrument Air Unavailability Tracking Data, 1/2006 - 4/2009
: Unit 3 Instrument Air System Annual Trend Report, 2005 - 2008
: NUREG 1022, Event Reporting Guidelines 10
: CFR 50.72 and 50.73, Rev. 2  
: 2008 - 2012 Indian Point Energy Center Business Plan (Safety), September 2008
: Entergy Quality Assurance Program Manual, Rev. 18
: Indian Point Unit 3 Top 20 Risk Significant System Classifications, April 2009
: IPEC Corrective Action Program Performance Indicators and Evaluations, 2007 - 2009
: IPEC SCWE Effectiveness Review, January 2008
: IPEC SCWE Confirmatory Assessment, March 2008
: IPEC Quarterly Trend Reports - 2008
: IP3-ANAL-FP-1503, "Unit 3 Appendix R Safe Shutdown Analysis"
: A-8
==LIST OF ACRONYMS==
==LIST OF ACRONYMS==
: [[ADA]] [[]]
: [[AC]] [[Alternating Current]]
MS Agency-wide Documents Access and Management System
: [[ADAMS]] [[Agency-Wide Documents Access and Management System]]
: [[AFW]] [[Auxiliary Feedwater]]
: [[AOP]] [[Abnormal Operating Procedure]]
: [[AOV]] [[Air Operated Valve]]
: [[ASME]] [[American Society of Mechanical Engineers]]
: [[CA]] [[Corrective Action]]
: [[CAP]] [[Corrective Action Program]]
: [[CAP]] [[Corrective Action Program]]
: [[CA]] [[]]
: [[CCW]] [[Component Cooling Water]]
RB  Corrective Action Review Board
: [[CDBI]] [[Component Design Bases Inspection]]
CFR Code of Federal Regulations
: [[CFR]] [[Code of Federal Regulations]]
CR Condition Report
: [[CR]] [[Condition Report]]
CRG  Condition Review Group
: [[CST]] [[Condensate Storage Tank]]
DRN  Document Revision Number
: [[CVCS]] [[Chemical and Volume Control System]]
DRP  Division of Reactor Projects
: [[DBD]] [[Design Basis Document]]
ECP  Employee Concerns Program
: [[DC]] [[Direct Current]]
IMC Inspection Manual Chapter
: [[DG]] [[Diesel Generator]]
LER Licensee Event Report
: [[DRS]] [[Division of Reactor Safety]]
MR Maintenance Rule
: [[EDG]] [[Emergency Diesel Generator]]
NCV Non-Cited Violation
: [[EOP]] [[Emergency Operating Procedure]]
: [[EPRI]] [[Electric Power Research Institute]]
: [[ERG]] [[[WOG] Emergency Response Guideline]]
: [[ESF]] [[Engineered Safeguards Feature]]
: [[ESFAS]] [[Engineered Safeguards Features Actuation System]]
: [[GL]] [[Generic Letter]]
: [[GPM]] [[Gallons Per Minute]]
: [[IMC]] [[Inspection Manual Chapter]]
: [[IN]] [[Information Notice]]
: [[IP]] [[Inspection Procedure]]
: [[IPEC]] [[Indian Point Energy Center]]
: [[IST]] [[In-Service Test]]
: [[JPM]] [[Job Performance Measure]]
: [[KV]] [[Kilo Volts]]
: [[LER]] [[Licensee Event Report]]
: [[LSG]] [[Long, Short, & Ground]]
: [[LSIG]] [[Long, Short, Instantaneous, & Ground]]
: [[LTOP]] [[Low Temperature Overpressure Protection]]
: [[MCC]] [[Motor Control Center]]
: [[MOV]] [[Motor Operated Valve]]
: [[MR]] [[Maintenance Rule]]
: [[NCV]] [[Non-Cited Violation]]
: [[NDE]] [[Non-Destructive Examination]]
: [[NPSH]] [[Net Positive Suction Head]]
NRC  Nuclear Regulatory Commission
NRC  Nuclear Regulatory Commission
: [[OE]] [[Operating Experience]]
OE  Operating Experience
: [[PA]] [[]]
OpESS Operating Experience Smart Sample
RS  Publicly Available Records System
Attachment
PI&R Problem Identification and Resolution
: [[P&ID]] [[Piping and Instrument Diagram]]
PM Preventive Maintenance
: [[PAB]] [[Primary Auxiliary Building]]
: [[ROP]] [[Reactor Oversight Process]]
: [[PARS]] [[Publicly Available Records]]
: [[SC]] [[]]
: [[PM]] [[Preventive Maintenance]]
WE Safety Conscious Work Environment
: [[PMT]] [[Post Maintenance Test]]
SDP Significance Determination Process
: [[PORV]] [[Power Operated Relief Valve]]
SSCs Structures, Systems and Components
: [[PSA]] [[Probabilistic Safety Assessment]]
: [[SR]] [[Surveillance Requirement]]
: [[RAW]] [[Risk Achievement Worth]]
: [[UFS]] [[]]
: [[RCP]] [[Reactor Coolant Pump]]
AR Updated Final Safety Analysis Report
: [[RCS]] [[Reactor Coolant System]]
: [[WO]] [[Work Order]]
: [[RHR]] [[Residual Heat Removal]]
: [[RRW]] [[Risk Reduction Worth]]
: [[RT]] [[Radiographic Test]]
: [[RWST]] [[Refueling Water Storage Tank]]
: [[SBO]] [[Station Blackout]]
: [[SDP]] [[Significance Determination Process]]
: [[SG]] [[Steam Generator]]
: [[SGTR]] [[Steam Generator Tube Rupture]]
: [[SI]] [[Safety Injection]]
: [[SPAR]] [[Standardized Plant Analysis Risk]]
: [[SQUG]] [[Seismic Qualification Utility Group]]
: [[SW]] [[Service Water]]
: [[TDAFW]] [[Turbine Driven Auxiliary Feedwater]]
: [[TDH]] [[Total Developed Head]]
: [[TRM]] [[Technical Requirements Manual]]
: [[TS]] [[Technical Specification]]
: [[UFSAR]] [[Updated Final Safety Analysis Report]]
: [[UT]] [[Ultrasonic Test]]
: [[VAC]] [[Volts Alternating Current]]
: [[WOG]] [[Westinghouse Owners Group]]
}}
}}

Revision as of 06:57, 25 August 2018

IR 05000247-09-007, on 07/20/2009 - 08/13/2009, for Indian Point Unit 2, Component Design Bases Inspection
ML092680234
Person / Time
Site: Indian Point Entergy icon.png
Issue date: 09/25/2009
From: Doerflein L T
Engineering Region 1 Branch 2
To: Pollock J E
Entergy Nuclear Operations
References
FOIA/PA-2011-0258 IR-09-007
Download: ML092680234 (48)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 September 25, 2009

Mr. Joseph Site Vice President Entergy Nuclear Operations, Inc.

Indian Point Energy Center 450 Broadway, GSB Buchanan, NY 10511-0249

SUBJECT: INDIAN POINT NUCLEAR GENERATING UNIT 2 - NRC COMPONENT DESIGN BASES INSPECTION REPORT NO. 05000247/2009007

Dear Mr. Pollock:

On August 13, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Indian Point Nuclear Generating Unit 2. The enclosed integrated inspection report documents the inspection results, which were discussed on August 13, 2009, with Mr. Donald Mayer and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

In conducting the inspection, the team examined the adequacy of selected components and operator actions to mitigate postulated transients, initiating events, and design basis accidents.

The inspection involved field walkdowns, examination of selected procedures, calculations and records, and interviews with station personnel.

This report documents three NRC-identified findings which were of very low safety significance (Green). Two of these findings were determined to involve violations of NRC requirements.

However, because of the very low safety significance of the violations and because they were entered into your corrective action program, the NRC is treating the violations as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region 1; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Senior Resident Inspector at Indian Point Nuclear Generating Unit 2. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I and the NRC Senior Resident Inspector at Indian Point Nuclear Generating Unit 2. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for the public inspection in the NRC Public Docket Room or from the Publicly Available Records component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/

Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety

Docket No. 50-247 License No. DPR-26

Enclosure:

Inspection Report No. 05000247/2009007

w/Attachment:

Supplemental Information

SUMMARY OF FINDINGS

IR 05000247/2009007; 07/20/2009 - 08/13/2009; Indian Point Unit 2; Component Design

Bases Inspection.

The report covers the Component Design Bases Inspection (CDBI) conducted by a team of four NRC inspectors and two NRC contractors. Three findings of very low risk significance (Green)were identified. Two of these findings were also considered to be NCVs. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using NRC Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). The cross-cutting aspects were determined using IMC 0305, "Operating Reactor Assessment Program." Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green.

The team identified a finding of very low safety significance involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergy did not verify the adequacy of design because they did not evaluate the impact of the installed Amptector discriminator instantaneous trip feature on breaker coordination.

Following identification Entergy entered the issue into the corrective action program and performed an operability assessment and extent-of-condition review.

The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of the 480Vac bus to respond to initiating events to prevent undesirable consequences. Specifically, load center Bus 6A (and 2A, 3A and 5A) would be incapable of meeting the design basis function when required if the incoming line breaker to the load center bus were to trip due to lack of coordination for a fault on a non-Class 1E circuit during a design basis accident. The finding was determined to be of very low safety significance because the design deficiency was confirmed not to result in loss of operability or functionality.

This finding was not assigned a cross-cutting aspect because the underlying cause was not indicative of current performance. (Section 1R21.2.1.1)

Green.

The team identified a finding of very low safety significance involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergy did not to ensure that the component cooling water pump hydraulic performance test procedures had acceptance criteria which incorporated applicable design limits sufficient to ensure continued pump operability. Specifically, if the pump flow rate had degraded to the lower limit of the acceptance band, as listed in the test acceptance criteria, the pump would not have been able to meet the design basis flow requirements at the minimum acceptable differential pressure listed in the test procedure. In addition, the iii test acceptance criteria for design basis flow rate and differential pressure had no allowance for measurement uncertainty of the test instruments. In response to this deficiency, Entergy's short-term corrective actions included initiation of a corrective action condition report and completion of an operability determination for the affected equipment.

The finding was more than minor because it was associated with the design control attribute of the Mitigating Cornerstone and affected the cornerstone objective of ensuring the capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the test acceptance criteria did not ensure that the No. 23 component cooling water pump remained capable of performing its safety function under design basis conditions. The finding had very low safety significance because it was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because Entergy's initial operability review, issue prioritization, and subsequent evaluation did not adequately assess actual pump performance.

[P.1 (c)] (Section 1R21.2.1.2)

Green.

The team identified a finding of very low safety significance because Entergy did not identify or evaluate material deficiencies of the city water system, as required by EN-LI-102, "Corrective Action Process." Specifically, Entergy did not identify or evaluate several degraded pipe supports on city water system piping in the utility tunnel, which represented reasonable doubt on system operability. The city water system provides a backup water supply for the condensate storage tank, fire fighting water supply, and provides alternate cooling to selected safety-related and risk significant pumps. The finding was not a violation because the city water piping, in the utility tunnel, is not safety-related, and the utility tunnel is not a safety-related or seismic structure. Entergy entered this issue into the corrective action program, assessed operability and extent-of-condition, and repaired one of the non-functioning pipe supports to restore additional margin. The finding was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern.

Specifically, the piping system could have potentially collapsed if additional pipe supports became degraded. The team determined the finding was of very low safety significance because it was not a design or qualification deficiency, did not represent of an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

iv

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because Entergy did not adequately implement the corrective action program with a low threshold for identifying issues.

P.1(a) (Section 1R21.2.2.1)

B. Licensee-Identified Violations

None.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R21 Component Design Bases Inspection (IP 71111.21)

.1 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the Indian Point Unit 2 Probabilistic Safety Assessment (PSA)and the NRC's Standardized Plant Analysis Risk (SPAR) model for Indian Point Unit 2.

Additionally, the team referenced the Risk-Informed Inspection Notebook for Indian Point Unit 2 (Revision 2.1a) in the selection of potential components and operator actions for review. In general, the selection process focused on components and operator actions that had a Risk Achievement Worth (RAW) factor greater than 1.3 or a Risk Reduction Worth (RRW) factor greater than 1.005. The components selected were located within both safety related and non-safety related systems, and included a variety of components such as pumps, breakers, ventilation fans, transformers, and valves.

The team initially compiled a list of components and operator actions based on the risk factors previously mentioned. Additionally, the team reviewed the previous CDBI report (05000247/2007007) and excluded the majority of those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 16 components, 5 operator actions and 6 operating experience (OE) items.

The team's evaluation of possible low design margin included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment also included items such as failed performance test results, corrective action history, repeated maintenance, Maintenance Rule (MR) (a)(1) status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry OE.

Finally, consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins. The margin review of operator actions included complexity of the action, time to complete the action, and extent-of-training on the action.

The inspection performed by the team was conducted as outlined in NRC Inspection Procedure (IP) 71111.21. This inspection effort included walkdowns of selected components, interviews with operators, system engineers and design engineers, and reviews of associated design documents and calculations to assess the adequacy of the components to meet design basis, licensing basis, and risk-informed beyond design basis requirements. Summaries of the reviews performed for each component, operator action, OE sample, and the specific inspection findings identified are discussed in the subsequent sections of this report. Documents reviewed for this inspection are listed in the Attachment.

.2 Results of Detailed Reviews

.2.1 Detailed Component and System Reviews (16 samples)

.2.1.1 Diesel Building Ventilation Fans 318 and 323

a. Inspection Scope

Motor control center (MCC) 26B supplies power to diesel building ventilation fans 318 and 323. The team reviewed the MCC 26B one-line and fan motor schematic diagrams to ensure the ventilation fans functioned as designed. The team also reviewed the coordination/protection calculation for load center Bus 6A incoming line and MCC 26B feeder breaker Amptector trip settings for design basis load flow conditions and protective device coordination. The team walked down MCC 26B, the fan motor controllers, and 480Vac Bus 6A to assess the observable material condition. The team reviewed the fan motor feeder cable sizing and calculated voltage available during design basis conditions for adequacy. The load center breakers were field inspected for conformance with design basis requirements for the type of Amptector trip unit installed.

In particular, LSG (long, short, & ground) type breakers potentially had Amptector discriminator trip units installed, whereas LSIG (long, short, instantaneous, & ground)type breakers did not. The team reviewed corrective action condition reports (CRs) and corrective maintenance history to identify potential recurring issues affecting reliability.

The team also reviewed surveillance testing on Amptector trip units for adequacy of results in accordance with design basis setting requirements.

b. Findings

Introduction.

The team identified a finding of very low safety significance (Green) involving a NCV of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergy did not verify the adequacy of design because they did not evaluate the impact of the installed LSG trip unit discriminator feature on breaker coordination.

Description.

During an inspection of 480Vac Bus 6A to independently assess Entergy design control (rating and use of LSG or LSIG type breakers), the team identified that Amptector discriminator instantaneous trips existed on the incoming line, emergency diesel generator (EDG) and bus cross-tie breaker. The team also determined that Entergy had not evaluated the discriminator circuit function in the breaker coordination study. Subsequently, during their extent-of-condition review, Entergy determined that type LSG trip units in load center Buses 5A, 2A and 3A were also affected. Entergy initiated CR-IP2-2009-3065 to evaluate the Amptector type LSG trip units without the discriminator defeated.

The Amptector discriminator circuit functions to provide an instantaneous breaker trip unless a minimum threshold current is exceeded prior to an overload condition (fault).

The breaker coordination study, Calculation FEX-00141-01, "IP2 Amptector Setting Verification, Sensor and Tolerances," specified that there are no instantaneous trips for the safety-related load center incoming line, EDG and bus-tie breakers, which would allow for their coordination with downstream non-Class 1E breakers during fault conditions. The breaker coordination analysis that demonstrates the adequacy of protection is required to satisfy Entergy Standard EEN-EE-S-010-IP2, "Electrical Separation Design Criteria," Section 5.10.5, Electrical Isolation Criteria, which includes demonstration that operation of Class 1E circuits, are not degraded below an acceptable level due to shorts or faults on the non-Class 1E side.

The team noted that the Amptector discriminator circuit could potentially cause the instantaneous trip of the 480Vac load center bus incoming line breaker during a postulated design basis accident, due to a fault on a non-Class 1E circuit, and result in the loss of the load center. The team concluded that the electrical isolation provided for the postulated fault condition, with the subject load center breaker Amptector discriminator function not being disabled, did not satisfy the requirements of Engineering Standard EEN-EE-S-010-IP2, "Electrical Separation Design Criteria," for electrical isolation of non-Class 1E circuits. Entergy performed an operability evaluation that determined that there was sufficient Class 1E load during all design basis operating conditions that served to disable the load center bus incoming line breaker Amptector discriminator circuit function (instantaneous trip) by exceeding the discriminator's minimum threshold current. However, the team also found that the minimum threshold current setpoint calibration had not been verified by Entergy during surveillance testing.

Nonetheless, the team concluded there was sufficient Class 1E load current available, well in excess of the manufacturer's rated tolerance of the electrical defeat setpoint for the Amptector trip units, to provide reasonable assurance that the discriminator circuit would be electrically defeated.

Analysis.

The team determined that Entergy's failure to verify the adequacy of design of the installed LSG type breakers as required by Engineering Standard EEN-EE-S-010-IP2 was a performance deficiency that was reasonably within Entergy's ability to foresee and prevent prior to July 2009. The team noted that Entergy had a previous opportunity to identify this issue. Specifically, Entergy's internal review of NRC Information Notice (IN)92-29, "Potential Breaker Miscoordination Caused By Instantaneous Trip Circuitry,"

represented a missed opportunity to evaluate this condition in 1992. On June 5, 1992, engineering had reviewed IN 92-29 and incorrectly concluded that only LSIG trip devices were installed at Unit 2.

The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of the 480Vac bus to respond to initiating events to prevent undesirable consequences. Specifically, load center Bus 6A (and 2A, 3A and 5A) would be incapable of meeting the design basis function when required if the incoming line breaker to the load center bus were to trip due to lack of coordination for a fault on a non-Class 1E circuit during a design basis accident. The team performed a Phase 1 SDP screening, in accordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," and determined the finding was of very low safety significance (Green) because the design deficiency was confirmed not to result in loss of operability or functionality.

This finding was not assigned a cross-cutting aspect because the underlying cause was not indicative of current performance. Specifically, the team did not identify any LSG breaker performance issues, Amptector calibrations, or associated engineering evaluations within the last several years that would have caused Entergy to re-revisit their response to NRC IN 92-29.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.

Contrary to the above, from June 5, 1992, until August 6, 2009, Entergy did not verify the adequacy of the design for protective device coordination regarding breakers configured with Amptector discriminator instantaneous trip circuits. Specifically, the load center Bus 6A incoming line breaker discriminator unit was neither defeated with an installed jumper nor were the conditions that were required to electrically defeat the circuit evaluated to ensure breaker coordination with non-Class 1E circuits. However, because this violation was of very low safety significance, and since it was entered in Entergy's corrective action program (CAP) as CR-IP2-2009-3065 this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000247/2009007-01, Failure to Evaluate the Impact on Breaker Coordination for the Westinghouse Amptector Type LSG Trip Unit Discriminator Feature)

.2.1.2 No. 23 Component Cooling Water Pump

a. Inspection Scope

The team reviewed design documents, including drawings, calculations, procedures, and the design basis document (DBD) to determine the design requirements for No. 23 component cooling water (CCW) pump. The team reviewed hydraulic analyses to verify adequacy of net positive suction head (NPSH) and verify adequacy of surveillance test acceptance criteria for pump minimum discharge pressure at the required flow rate. The team reviewed in-service test (IST) results to verify acceptance criteria were met and any potential performance degradation was identified. In addition, the team reviewed Entergy's response and actions related to NRC Bulletin 88-04, "Potential Safety-Related Pump Loss," to assess implementation of OE related to pump minimum flow requirements, and pump-to-pump interaction. The team also reviewed electrical calculations, drawings, and pump brake horsepower requirements to determine if the motor capacity was adequate for the loading requirements. The team reviewed motor breaker Amptector settings, motor feeder cable ampacity and cable short circuit current capability to determine whether appropriate electrical protection coordination margins had been applied and whether the feeder cable had been properly sized for the maximum loading and short circuit current capability requirements.

The team performed a walkdown of the CCW pump area to assess the material condition of the pump and motor driver. The team reviewed preventive and corrective maintenance records to ensure that Entergy properly maintained the CCW pump. The team also reviewed corrective action documents to ensure that Entergy identified and corrected deficiencies associated with the CCW pump at an appropriate threshold.

b. Findings

Introduction.

The team identified a finding of very low safety significance (Green) involving a NCV of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergy did not ensure the CCW pump hydraulic performance test procedures had acceptance criteria which incorporated the applicable design limits sufficient to ensure continued pump operability.

Description.

During a self-assessment in March 2009, Entergy identified an IST pump test acceptance criteria deficiency (CR 2009-0868). Specifically, Entergy identified that they had not appropriately incorporated instrument uncertainty into test acceptance criteria. For the CCW pumps, Entergy determined that they remained operable based on the available margin as indicated by their January 2009 IST for each of the respective CCW pumps. On April 1, Entergy expanded corrective actions to include detailed reviews to determine whether pump tests adequately incorporated design bases analytical limits. The team noted that Entergy's evaluation was still in-progress, with a due date of mid-September 2009.

At Indian Point 2, design basis hydraulic performance of the CCW pumps is verified by the American Society of Mechanical Engineers (ASME)Section XI in-service testing program. The team noted that the minimum CCW pump flow rate and differential pressure requirements were developed in Westinghouse Report No. WCAP-12312, "Safety Evaluation for an Ultimate Heat Sink Temperature of 95 ºF at Indian Point Unit 2," Revision 2, January 2004. The minimum performance criterion for the CCW pumps was determined to be 3500 gpm at 215.8 feet of total developed head (TDH). The team reviewed CCW pump IST procedure 2-PT-Q030C, "23 Component Cooling Water Pump," Revision 18, and noted that the acceptance criterion for pump flow rate was in the range of 3430 to 3500 gpm at a TDH of 215.8 ft. The team concluded that the lower limit for acceptance criterion of 3430 gpm for flow rate at 215.8 TDH was less than, and therefore, non-conservative when compared to the minimum analysis value for pump flow rate of 3500 gpm determined in Westinghouse WCAP No. 12312 at a TDH of 215.8 feet. The team also noted that procedure Step 4.5.1.2, which calculated pump discharge pressure, had a value of 1.5 psi added to the recorded discharge pressure.

Entergy engineering personnel stated that this value was added to the discharge pressure to account for a check valve between the pump discharge and gauge pressure measuring tap, and that it was verified by field measurement. The team determined that this was not a valid number to be added to the discharge pressure because the field measurement did not account for the gauge elevation difference between the pump outlet gauge and the gauge used at the pressure tap. Using the formula for pressure drop through a check valve, the team independently determined that a more appropriate correction would be about 1.5 feet instead of 1.5 psi. Additionally, there was no allowance for instrument measurement uncertainty in the test acceptance criteria. As a result, the team concluded that the analytical value for the pump acceptance criteria was non-conservative by 70 gpm in flow rate, and about 2 feet TDH, without accounting for instrument uncertainty.

Based on these non-conservative values in the CCW pump IST acceptance criteria, the team questioned the operability of the No. 23 CCW pump because Entergy's April 16, 2009, IST recorded a CCW pump flow rate of 3460 gpm at 216.0 feet TDH (compared to the design limit of 3500 gpm at 215.8 feet TDH). Using the more appropriate correction factor on discharge pressure measurement, the recorded TDH should have been 214.0 feet. The inspectors plotted the data from the IST results on the design basis pump curve, and determined that the pump did not meet the minimum hydraulic performance requirements contained in WCAP No. 12312 during the April 2009 performance test. The team concluded that the No. 23 CCW pump actually had negative margin once appropriate and conservative values for design analytical limits and instrument uncertainty were factored in. Based on the team's assessment, the data indicated that the pump actually failed the test by about 6 feet of TDH at a corrected flow rate of 3500 gpm. The team noted that Entergy had noted the "low margin" during the April 2009 IST and entered the concern into their Margin Management Database; however, they did not assess the pump for continued operability, especially considering that they had lost all of the margin from the January 2009 IST that had formed the basis of their previous operability determination.

The team also noted that Entergy performed the No. 23 CCW pump IST again in July 2009 without updating the IST procedure and without performing an engineering evaluation to bound the condition to ensure that they adequately maintained the design bases. The team noted that the pump appeared to have more margin based on the July IST. Subsequently, Entergy provided an evaluation based on the July IST (considering instrument uncertainty and design bases analytical limits) that showed that the pump was operable as of July 09, 2009. The team agreed that there was more margin in the July test results which indicated that the pump met its design bases requirements for flow rate and TDH. In response to the team's concerns and identified deficiencies, Entergy initiated CR 2009-3807. Entergy's additional short-term planned corrective actions included performing an apparent cause evaluation and revising the CCW IST procedure to include appropriate analytical limits and instrument uncertainty values prior to the next scheduled IST.

The team noted that Entergy had missed several opportunities to identify and correct this IST shortcoming based on related issues within their CAP. Specifically, in 2006, CR IP2-2006-06511 identified concerns where instrument uncertainty was not considered in pump test acceptance criteria, and assigned an action to system and design engineering to "develop new acceptance criteria to account for instrument inaccuracy where needed." However, engineering did not complete the recommended actions from this 2006 CR. In 2007, the NRC identified a similar issue involving non-conservative analytical limits during the Indian Point Unit 3 CDBI (NCV 05000286/2007006-03, Non-Conservative Calculation for TDAFW Pump Discharge Pressure Used for Surveillance Testing). Entergy had performed an extent-of-condition review for Unit 2, but only reviewed the test acceptance criteria of the Unit 2 turbine driven auxiliary feedwater (TDAFW) pump.

Analysis.

The team determined that Entergy's failure to ensure that the CCW pump hydraulic performance test procedures had acceptance criteria that incorporated the limits from applicable design documents was a performance deficiency that was reasonably within Entergy's ability to foresee and prevent prior to July 2009. The team noted that Entergy had missed several opportunities to identify and correct this deficiency dating back to 2006. In addition, following identification in March 2009, Entergy did not adequately prioritize and evaluate the condition to ensure continued CCW pump operability.

The team determined that the performance deficiency was similar to NRC IMC 0612, Appendix E, "Examples of Minor Issues," Example 3.j, in that the deficient hydraulic test acceptance criteria resulted in a condition where there was a reasonable doubt with respect to operability of the CCW pump. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of the CCW pump to respond to initiating events to prevent undesirable consequences. Specifically, the test acceptance criterion used did not ensure that the No. 23 CCW pump remained capable of performing its safety function under design bases conditions. The team performed a Phase 1 SDP screening, in accordance with NRC IMC 0609, Attachment 4, "Phase 1 -

Initial Screening and Characterization of Findings," and determined the finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The team concluded that there was no loss of CCW safety function based on (1) Entergy's reasonable determination of continued operability based on the July IST results, (2) no significant corrective maintenance performed on No. 23 CCW pump between the January and July ISTs, and (3) review of the river water temperature trend for 2009 (a maximum river water temperature of 78 ºF was recorded in July).

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because Entergy's initial operability review, issue prioritization, and subsequent evaluation failed to adequately assess actual pump performance. Specifically, on March 5, 2009, Entergy identified pump testing deficiencies related to instrument uncertainty, and subsequently identified that No. 23 CCW pump had low margin, but did not adequately prioritize and evaluate the No. 23 CCW pump's performance with respect to its required design bases to ensure continued operability during 2009. (IMC 0305, aspect P.1(c))

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, from January 2004 until August 10, 2009, Entergy did not ensure that the CCW design basis for pump hydraulic performance was correctly translated into the CCW IST procedures. Specifically, Entergy did not include the appropriate analytical limits and instrument uncertainties in the development of the hydraulic performance test acceptance criteria of 3500 gpm at 215.8 feet TDH for the demonstration of operability of the CCW pumps. However, because this violation was of very low safety significance, and since it was entered in Entergy's CAP as CR-IP2-2009-3087 this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000247/2009007-02, Failure to Ensure That the CCW Pump Hydraulic Performance Test Procedures Had Acceptance Criteria That Incorporated the Limits from Applicable Design Documents)

.2.1.3 Steam Admission Valve to the Turbine Driven Auxiliary Feedwater Pump (PCV-1139)

a. Inspection Scope

The team inspected air-operated valve (AOV) PCV-1139 to verify its ability to meet the design basis requirements in response to transient and accident events as described in the Updated Final Safety Analysis Report (UFSAR), DBD, and Technical Specifications (TSs). The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed diagnostic test results and stroke test documentation to verify acceptance criteria were met. The team reviewed drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team reviewed the maintenance and functional history of valve PCV-1139 by sampling CRs, the system health report, and local maintenance procedures to verify that deficiencies were appropriately identified and resolved, and that the valve was properly maintained. The team reviewed the backup nitrogen supply system for PCV-1139 to determine if design assumptions were supported by procedural operation of the system. The team interviewed the AOV program and system engineers to gain an understanding of maintenance issues and overall reliability of the valve. The team also conducted several detailed walkdowns to assess the material condition of the valve and its support systems, and to ensure adequate configuration control.

b. Findings

No findings of significance were identified.

.2.1.4 Engineered Safeguards Features Actuation System

a. Inspection Scope

The team inspected the engineered safeguards features actuation system (ESFAS) to verify its ability to meet design basis requirements during plant transients and accidents. The ESFAS processes inputs from plant instrumentation and control systems using a relay based logic network to actuate controlled components (pumps, valves, fans, etc.) when the design logic for a particular ESF is satisfied. The team reviewed design calculations, drawings, plant procedures and completed surveillance tests to ensure that the system was designed, operated, and tested in accordance with design and licensing bases documents that included the ESFAS DBD, the PSA, the UFSAR and TSs. The team performed walkdowns to assess the material condition of accessible portions of the system and Entergy's configuration control. The team reviewed a sample of maintenance work orders, CRs and system health reports to assess system performance and to ensure that Entergy identified and corrected deficiencies at an appropriate threshold. The team also discussed the design documentation and maintenance history of the ESFAS with the responsible design and system engineers.

b. Findings

No findings of significance were identified.

.2.1.5 Turbine Driven Auxiliary Feedwater Pump (No. 22 Auxiliary Boiler Feedwater Pump)

a. Inspection Scope

The team reviewed design documents, including drawings, calculations, procedures, and the DBD to determine the design requirements for the TDAFW pump. The team reviewed hydraulic analyses to verify adequacy of NPSH and to verify adequacy of surveillance test acceptance criteria for pump minimum discharge pressure at the required flow rate. The team reviewed IST results to verify acceptance criteria were met and any potential performance degradation identified. The team reviewed pump actuation logic test results to ensure the TDAFW pump would start in accidents and events as described in the UFSAR. In addition, the team reviewed Entergy's response and actions related to NRC IE Bulletin 88-04, "Potential Safety-Related Pump Loss," to assess implementation of OE related to pump minimum flow requirements, and pump-to-pump interaction. The team reviewed turbine protection features, including overspeed tests, and turbine casing relief valve sizing and testing, to ensure the equipment protection features were adequate. The team reviewed condensate storage tank (CST) design criteria, including seismic qualification and usable volume calculations to ensure the TDAFW pump, in conjunction with the motor driven AFW pump had an adequate safety-grade water supply. The team reviewed the use of city water as a backup supply for the suction source for the TDAFW pump to ensure sufficient flow would be provided and to verify that Entergy adequately tested the associated valves to perform their function.

The team performed several walkdowns of the TDAFW pump area and supporting equipment to determine whether the alignment was in accordance with design basis and procedural requirements, and to assess the material condition of the pump and turbine.

The team reviewed preventive and corrective maintenance records to ensure that Entergy properly maintained the TDAFW pump. The team also reviewed corrective action documents to ensure that Entergy identified and corrected deficiencies associated with the TDAFW pump at an appropriate threshold.

b. Findings

No findings of significance were identified.

.2.1.6 Station Blackout/Appendix "R" Diesel Generator

a. Inspection Scope

The team reviewed the analysis for the station blackout (SBO)/Appendix "R" diesel generator (DG) system for load flow and short circuit current requirements to determine the design basis for maximum load, DG sizing, and protective device coordination. The team reviewed protective relay setting requirements, relay surveillance tests, and performed walkdowns of the protective relay settings to assess conformance with design bases IST. The team reviewed the vendor DG acceptance tests, and generator one-line and breaker control schematic diagrams to assess design basis requirements.

The team reviewed Technical Requirements Manual (TRM) surveillance requirements and surveillance test results for adequacy. The team also reviewed CRs to identify potential recurring issues that could impact system reliability. The team performed several walkdowns of the DG and associated switchgear to assess the observable material condition and Entergy's configuration control.

b. Findings

No findings of significance were identified.

2.1.7 No. 22 Residual Heat Removal Pump

a. Inspection Scope

The team reviewed design documents, including drawings, calculations, procedures, and the DBD, to determine the design requirements for the No. 22 residual heat removal (RHR) pump. The team reviewed hydraulic analyses to verify NPSH adequacy during the injection and sump recirculation modes of operation. The team verified adequacy of surveillance test acceptance criteria for pump minimum discharge pressure at the required flow rate. The team reviewed IST results to verify acceptance criteria were met and any potential performance degradation identified. In addition, the team reviewed Entergy's response and actions related to NRC IE Bulletin 88-04, "Potential Safety-Related Pump Loss," and Generic Letter 87-12, "Loss of RHR while the RCS is Partially Filled," to assess Entergy's implementation of OE related to pump minimum flow requirements, pump-to-pump interaction, and mid-loop operation. The team also reviewed electrical calculations, drawings, and pump brake horsepower requirements to determine if the motor capacity was adequate for the loading requirements. The team reviewed motor breaker Amptector settings, motor feeder cable ampacity and cable short circuit current capability to determine whether appropriate electrical protection coordination margins had been applied and whether the feeder cable had been properly sized for the maximum loading and short circuit current capability requirements.

The team performed a walkdown of the RHR pump area and supporting equipment to assess the material condition of the pump and motor driver, and reviewed a recent modification performed for room flooding mitigation. The team reviewed preventive and corrective maintenance records to ensure that Entergy properly maintained the RHR pump. The team also reviewed corrective action documents to ensure that Entergy identified and corrected deficiencies associated with the RHR pump at an appropriate threshold.

b. Findings

No findings of significance were identified.

2.1.8 Motor Control Center 26A

a. Inspection Scope

The team inspected MCC-26A to verify its ability to meet design basis requirements during plant transients and accidents. The MCC provides 480 volts alternating current (Vac) power to operate safety-related components that include motor operated valves (MOVs), fans and transformers. The team reviewed design calculations, drawings and plant procedures to ensure that the MCC was designed and operated in accordance with design and licensing bases documents that included the 480Vac system DBD, the PSA, the UFSAR and TSs. The team performed walkdowns to assess the material condition of the MCC and Entergy's configuration control. The team reviewed a sample of maintenance work orders, CRs and system health reports to assess system performance and to ensure that Entergy identified and corrected deficiencies at an appropriate threshold. The team also discussed the design documentation and maintenance history of the MCC with the responsible design and system engineers to assess overall reliability.

b. Findings

No findings of significance were identified.

.2.1.9 Main Steam Atmospheric Steam Dump Valves (PCV-1134, 1135, 1136, & 1137)

a. Inspection Scope

The team inspected the air-operated atmospheric steam dump valves to verify their ability to meet the design basis requirements in response to transient and accident events. The team reviewed applicable portions of the UFSAR, main steam DBD, TSs, and drawings to identify design basis requirements for these valves. The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed diagnostic test results and stroke test documentation to verify acceptance criteria were met. The team reviewed drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team reviewed the maintenance and functional history of the atmospheric steam dump valves by sampling CRs, the system health report, and local maintenance procedures to verify that deficiencies were appropriately identified and resolved, and that valves were properly maintained. The team reviewed the backup nitrogen supply system for the atmospheric steam dump valves to determine if design assumptions were supported by procedural operation of the system. The team interviewed the AOV program and system engineers to gain an understanding of maintenance issues and overall reliability of the valves. The team also conducted several detailed walkdowns to assess the material condition of the valves and their support systems, and to ensure adequate configuration control.

b. Findings

No findings of significance were identified.

.2.1.1 0 DC Distribution Panel 22

a. Inspection Scope

The team inspected DC distribution panel No. 22 to verify its ability to meet the design basis requirements in response to transient and accident events. The team reviewed the No. 22 battery system calculation with respect to the DC distribution panel No. 22 loading to determine the design basis for maximum load and minimum required voltage at selected branch circuits for conformance with design basis requirements. The team also reviewed the distribution panel vendor ratings for conformance with the design basis. The team reviewed the coordination/protection calculation to assess the design basis load and short circuit current conditions. The team walked down the distribution panel to assess the observable material condition and conformance with design documentation. The team reviewed the procurement engineering technical evaluation for replacement breakers for conformance with design basis requirements. Also, the 0team reviewed CRs and corrective maintenance history to identify potential recurring issues that could impact DC distribution system reliability.

b. Findings

No findings of significance were identified.

.2.1.1 1 Electrical Bus 2 Fast Transfer (6.9 kV Circuit Breakers UT2/UT2-ST5)

a. Inspection Scope

The team inspected the electrical bus fast transfer feature to verify its ability to meet design basis requirements during plant transients and accidents. Following a turbine trip, the electrical bus 2 fast transfer circuitry controls 6.9kV feeder circuit breakers (UT2 and UT2-ST5) to disconnect the normal feed from the unit auxiliary transformer and connect the feed from bus 5 which is powered by the station auxiliary transformer. The team reviewed the design calculations, drawings and plant procedures to ensure the bus transfer was designed and operated in accordance with design and licensing bases documents that included the UFSAR and TSs. The team reviewed surveillance test procedures to ensure that Entergy had properly incorporated the associated design features and TS requirements. The team also reviewed completed surveillance tests to ensure the acceptance criteria were met. The team reviewed the results of the circuit breaker closure time testing to ensure that they were consistent with the design documentation. The team performed walkdowns to assess the material condition of the associated switchgear and Entergy's configuration control. The team reviewed a sample of maintenance work orders, CRs and system health reports to assess system performance and to ensure that Entergy identified and corrected deficiencies at an appropriate threshold. The team also discussed the design documentation and maintenance history of the bus fast transfer system with the responsible design and system engineers to identify potential recurring issues that could impact the reliability of the fast transfer control system.

b. Findings

No findings of significance were identified.

.2.1.1 2

Motor and Turbine Driven Auxiliary Feedwater Pump Flow Control Valves (FCV-406A,B,C,D & FCV-405A,B,C,D)

a. Inspection Scope

The team inspected the air-operated feedwater flow control valves for both the motor and turbine driven AFW pumps to verify their ability to meet the design basis requirements in response to transient and accident events. The team reviewed applicable portions of the UFSAR, the main steam and AFW DBDs, and the TSs, to identify design basis requirements for these valves. The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed diagnostic test results and stroke test documentation to verify acceptance criteria were met. The team reviewed drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team reviewed the maintenance and functional history of the feedwater flow control valves by sampling CRs, the system health report, and local maintenance procedures to verify that deficiencies were appropriately identified and resolved, and that the valves were properly maintained. The team reviewed the backup nitrogen supply for the AFW system to determine if there was sufficient capacity to support design assumptions for system operation following a loss-of-instrument air. The team interviewed the AOV program and system engineers to gain an understanding of maintenance issues and overall reliability of the valves. The team also conducted several detailed walkdowns to assess the material condition of the valves and their support systems, and to ensure adequate configuration control.

b. Findings

No findings of significance were identified.

.2.1.1 3 Station Service Transformer No. 5

a. Inspection Scope

The team reviewed station service transformer No. 5 to verify its capability to provide a reliable source of offsite power from 6.9 kV electrical Bus 5 to the safety-related electrical Bus 5A. The team reviewed one line diagrams and vendor test results for impedance data, to confirm that correct transformer impedances were utilized in design analyses. The team confirmed the adequacy of the overcurrent relay setting calculation for design basis loading and protective relay setting requirements. The team walked down the transformer overcurrent protective relays to observe settings and to determine conformance with relay setting sheets. The team reviewed the transformer modification history for potential impact on the design basis. The team also walked down the transformer and switchgear to assess the observable material condition and to observe transformer temperature monitoring indicators and controls. The team also reviewed the corrective maintenance history and CRs to identify potential recurring issues that could impact system reliability.

b. Findings

No findings of significance were identified.

.2.1.1 4 Common Cause Failure of the Emergency Diesel Generators

a. Inspection Scope

The team performed a focused review for potential common cause failure of the three EDGs. The team performed several detailed walkdowns of the EDG building to ascertain whether design or operational conditions existed that would compromise the performance of all three EDGs. In particular, the team reviewed seismic evaluations of control cabinets for EDG ventilation fans and EDG jacket water expansion tanks to ensure that the selected equipment could withstand seismic loads. The team walked down the areas external to the EDG building to look for seismic interaction potential (Seismic II/I), and assessed the seismic ruggedness of a transmission line tower located near the EDG building. The team reviewed internal flooding studies to ensure that there was no potential to flood the building and cause common cause failure of the EDGs.

The team reviewed the EDG air start system configuration which included a connection between two of the EDG air start accumulators to ensure that any failure in the connecting air lines would not result in loss of air start capability for the two associated EDGs. The team reviewed EDG fuel oil sample results to ensure the quality of the fuel oil.

The EDG heat exchangers are cooled by service water (SW) delivered to the building through a common buried pipe. The team reviewed recent pressure integrity test results for the buried pipe to ensure that the pipe was not experiencing any leakage. The team also conducted several detailed walkdowns of the accessible portions of the SW piping, EDG ventilation system, and fuel oil system to assess the material condition of these essential support systems, and to ensure adequate configuration control.

b. Findings

No findings of significance were identified.

.2.1.1 5 Power Operated Relief Valve Block Valves (MOV-535 and MOV-536)

a. Inspection Scope

The team inspected the electrical design and operation of the power operated relief valve (PORV) block valves. The review included the valve operation when the PORVs are used for plant pressure control at normal plant operating temperature and pressure as well as their use for plant low temperature overpressure protection (LTOP) when the plant is shut down. The team reviewed design calculations, drawings, plant procedures and completed surveillance tests to ensure that the valves were designed, operated and tested in accordance with design and licensing bases documents that included the UFSAR and TSs. The team reviewed thermal overload settings and system voltage loss calculations to verify the valves would operate under the most limiting plant conditions.

The team also reviewed a sample of recent system health reports, maintenance work orders and CRs to assess the performance history and condition of the valves.

b. Findings

No findings of significance were identified.

2.1.16 Main Steam Isolation Valve (MS-1-24)

a. Inspection Scope

The team inspected air-operated valve MS-1-24 to verify its ability to meet the design basis requirements in response to transient and accident events, including the prevention of uncontrolled flow of steam following a steam line break. The team reviewed applicable portions of the UFSAR, the main steam DBD, and the TSs, to identify design basis requirements for the valve. The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed stroke test documentation to verify acceptance criteria were met. The team reviewed drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team reviewed the maintenance and functional history of MS-1-24 by sampling CRs, the system health report, and local maintenance procedures to verify that deficiencies were appropriately identified and resolved, and that valves were properly maintained. The team interviewed the maintenance and system engineers to gain an understanding of maintenance issues and overall reliability of the valves. The team also conducted several detailed walkdowns to assess the material condition of the valve and its support systems, and to ensure adequate configuration control.

b. Findings

No findings of significance were identified.

.2.2 Review of Low Margin Operator Actions (5 samples)

The team assessed manual operator actions and selected a sample of five operator actions for detailed review based upon risk significance, time urgency, and factors affecting the likelihood of human error. The operator actions were selected from a PSA ranking of operator action importance based on RAW and RRW values. The non-PSA considerations in the selection process included the following factors:

  • Margin between the time needed to complete the actions and the time available prior to adverse reactor consequences;
  • Complexity of the actions;
  • Reliability and/or redundancy of components associated with the actions;
  • Extent of actions to be performed outside of the control room;
  • Procedural guidance to the operators; and
  • Amount of relevant operator training conducted.

.2.2.1 Align City Water for Backup Cooling to Safety Injection/Residual Heat Removal Pumps

following Loss of Component Cooling Water

a. Inspection Scope

The team evaluated manual operator actions to align city water backup cooling to the safety injection (SI) and RHR pumps, following a loss of CCW event, to verify operator actions were consistent with design and licensing bases. Specifically, operator critical tasks included:

  • Install temporary hoses
  • Align CCW, primary water, and city water valves The team interviewed licensed and non-licensed operators, reviewed associated operating procedures and operator training, observed an in-field operator job performance measure (JPM) to install temporary hoses and align local CCW, primary water, and city water valves, and independently inventoried pre-staged equipment and tools, to evaluate the operators' ability to perform the required actions. In addition, the team walked down local piping and valves associated with the critical tasks to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions. The team also reviewed equipment deficiency reports, and performed infield observations, to assess the material condition of the associated piping, valves, and support systems.

In addition, the team walked down selected accessible portions of the city water system to independently assess Entergy's configuration control and the system's material condition. The walkdowns included the city water storage tank; an above ground inspection from the city water tank to the utility tunnel entrance to check for evidence of underground pipe leakage; the utility tunnel; and the AFW, RHR, SI, and charging pump rooms.

b. Findings

Introduction.

The team identified a finding of very low safety significance (Green) because Entergy did not identify or evaluate material deficiencies of the city water system, as required by EN-LI-102, "Corrective Action Process." The finding was not a violation because the city water piping, in the utility tunnel, is not safety-related, and the utility tunnel is not a safety-related or seismic structure.

Description.

City water piping is routed underground from the city water storage tank to the utility tunnel, at the air monitoring house. The utility tunnel runs underground from the air monitoring house to the screen well house. At various locations throughout the tunnel, city water branch lines come off of the city water header pipe, to provide a backup water supply for several safety-related or risk significant components. The city water system is credited to mitigate the consequences of a plant fire (fire safe shutdown analysis) and a station blackout (SBO) event. The city water system also provides a backup water supply for the CST and fire fighting water supply, and provides alternate cooling to selected safety-related and risk significant pumps. The city water system is required to be operable in accordance with TRM 3.7.E.

During a utility tunnel walkdown on July 23, 2009, the team identified a degraded pipe support on the city water header pipe. Entergy entered this issue into their CAP as CR 2009-2850, performed an extent-of-condition walkdown and a prompt operability assessment. Subsequently, Entergy identified several additional degraded supports on the city water pipe. Entergy determined that the city water system remained operable because the greatest unsupported span was not more than 22 feet. American Society of Mechanical Engineers (ASME) B31.1, "Power Piping," recommended that the maximum unsupported span not exceed 27 feet, for this size water service piping.

On August 4, 2009, the team performed an additional utility tunnel walkdown to independently assess Entergy's evaluation and extent-of-condition review. The team identified several additional degraded pipe supports on the city water header pipe, one of which caused the original unsupported span to increase from 22 feet to 38 feet in one section of the piping. Entergy entered this issue into their CAP as CR 2009-3046, performed an extent-of-condition walkdown and a prompt engineering analysis. Entergy concluded that although the available pipe stress margin was reduced, the city water system remained operable because the pipe stress was less than the ASME B31.1 allowable stress for the pipe. The team noted that Entergy used conservative assumptions in their analysis and concluded that the Entergy's assessment was reasonable. In addition, the team determined that the city water system was properly scoped in Entergy's MR program and the degraded supports would not have required a MR (a)(1) monitoring plan.

Subsequently, work order 00171798 repaired one of the degraded pipe supports to reduce the unsupported span to 22 feet, thereby increasing the margin of the pipe support system. CR 2009-2850, corrective action CA-2, required a follow-up engineering analysis with a formal calculation. Entergy planned additional long-term corrective actions under their existing and on-going utility tunnel refurbishment plan.

Analysis.

The team determined that the failure to identify or evaluate material deficiencies of the city water system was a performance deficiency that was reasonably within Entergy's ability to foresee and prevent prior to July 2009. Specifically, Entergy did not identify or evaluate several degraded pipe supports on the city water header pipe in the utility tunnel, as required by EN-LI-102, "Corrective Action Process." As a result, the degraded supports represented reasonable doubt on the operability of the city water system. The finding was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern.

Specifically, this risk significant piping system could have potentially collapsed if additional pipe supports became degraded. The team performed a Phase 1 SDP screening, in accordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," and determined the finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because Entergy did not adequately implement the CAP with a low threshold for identifying issues. Specifically, Entergy personnel performed frequent activities in the utility tunnel within the last two years, but did not identify the degraded supports and did not initiate a corrective action CR, as required by EN-LI-102, "Corrective Action Process." (IMC 0305, aspect P.1(a))

Enforcement.

Enforcement action does not apply because the performance deficiency did not involve a violation of a regulatory requirement. Entergy entered this issue into their CAP as CR IP2-2009-2850 and 3046. Because this finding does not involve a violation of regulatory requirements and has very low safety significance, it is identified as FIN 05000247/2009007-03. (FIN 050000247/2009007-03, Failure to Identify Several Degraded City Water System Pipe Supports in the Utility Tunnel)

.2.2.2 Primary Feed and Bleed Cooling following Loss of Main and Auxiliary Feedwater

a. Inspection Scope

The team evaluated manual operator actions to establish primary feed and bleed, following a complete loss of main feedwater and AFW (e.g., loss of secondary heat sink), to verify operator actions were consistent with design and licensing bases.

Specifically, operator critical tasks included:

  • Initiate SI
  • Open both pressurizer PORV block valves
  • Open both pressurizer PORVs
  • Verify SI flow
  • Verify PORVs open The team interviewed licensed operators, reviewed associated operating procedures and operator training, and observed a tabletop demonstration of a loss of secondary heat sink, to evaluate the operators' ability to perform the required actions. In addition, the team walked down main control room panels to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions.

The team also walked down selected in-field components and reviewed equipment deficiency reports, engineering evaluations, and surveillance test results to assess the material condition of the associated pumps, valves, and support systems.

b. Findings

No findings of significance were identified.

.2.2.3 Align Condensate for Secondary Heat Removal following Loss of Main and Auxiliary Feedwater

a. Inspection Scope

The team evaluated manual operator actions to establish condensate flow to at least one steam generator (SG), following a complete loss of main feedwater and AFW (e.g.,

loss of secondary heat sink), to verify operator actions were consistent with design and licensing bases. Specifically, operator critical tasks included:

  • Block SI actuation signal
  • Depressurize at least one SG to less than condensate pump discharge pressure
  • Open feedwater flow control valves The team interviewed licensed and non-licensed operators, reviewed associated operating procedures and operator training, observed a tabletop demonstration of a loss of secondary heat sink, observed an in-field operator JPM to install a temporary instrument air control line on a feedwater regulating bypass valve, and independently inventoried pre-staged equipment and tools, to evaluate the operators' ability to perform the required actions. The team walked down main control room panels and observed an in-field simulation of the local manual actions to disconnect and lift an electrical wire from a control relay to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions. The team also walked down selected in-field components and reviewed equipment deficiency reports to assess the material condition of the associated pumps, valves, and support systems.

b. Findings

No findings of significance were identified.

.2.2.4 Early Isolation of Ruptured Steam Generator

a. Inspection Scope

The team evaluated manual operator actions to prevent overfilling a ruptured SG, during a postulated design basis SG tube rupture (SGTR), to verify operator actions were consistent with design and licensing bases. Specifically, operator critical tasks included:

  • Identify the ruptured SG
  • Stop main and auxiliary feedwater flow into the ruptured SG The team interviewed licensed operators and operator simulator instructors, reviewed associated operating procedures and operator training, and observed operator response during a simulator scenario of a SGTR event, to evaluate the operators' ability to perform the required actions. The team walked down applicable control panels in the simulator and the main control room to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions. The team also walked down selected in-field components and reviewed equipment deficiency reports to assess the material condition of the associated pumps, valves, and support systems.

b. Findings

No findings of significance were identified.

.2.2.5 Align City Water for Backup Cooling to Charging Pumps following Loss of Component

Cooling Water

a. Inspection Scope

The team evaluated manual operator actions to align city water backup cooling to the charging pumps, following a loss of CCW event, to verify operator actions were consistent with design and licensing bases. Specifically, operator critical tasks included:

  • Align charging pump in manual at maximum speed
  • Install a temporary hose
  • Align CCW and city water valves The team interviewed licensed and non-licensed operators, reviewed associated operating procedures and operator training, observed a tabletop demonstration of a loss of CCW, observed an in-field operator JPM to install a temporary hose and to align local CCW and city water valves, and independently inventoried pre-staged equipment and tools, to evaluate the operators' ability to perform the required actions. In addition, the team walked down local piping and valves associated with the critical tasks to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of Entergy's operating procedures and risk assumptions. The team also reviewed equipment deficiency reports, as well as direct observation, to assess the material condition of the associated piping, valves, and support systems.

In addition, the team walked down selected accessible portions of the city water system to independently assess Entergy's configuration control and the system's material condition. The walkdowns included the city water storage tank; an above ground inspection from the city water tank to the utility tunnel entrance to check for evidence of underground pipe leakage; the utility tunnel; and the AFW, RHR, SI, and charging pump rooms.

b. Findings

No additional findings of significance were identified. (See Section 1R21.2.2.1 for a city water related finding.)

.2.3 Review of Industry Operating Experience and Generic Issues (6 samples)

The team reviewed selected OE issues for applicability at Indian Point Unit 2. The team performed a detailed review of the OE issues listed below to verify that Entergy had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.

.2.3.1 Operating Experience Smart Sample FY 2008-01 -

Negative Trend and Recurring Events Involving Emergency Diesel Generators

a. Inspection Scope

NRC Operating Experience Smart Sample (OpESS) FY 2008-01 is directly related to NRC IN 2007-27, "Recurring Events Involving Emergency Diesel Generator Operability" and NRC IN 2007-36, "Emergency Diesel Generator Voltage Regulator Problems." The team reviewed Entergy's evaluation of IN 2007-27 and IN 2007-36 and their associated corrective actions. The team reviewed Entergy's EDG system health reports, EDG CRs and work orders, the leakage database, and surveillance test results to verify that Entergy appropriately dispositioned EDG concerns. Additionally, the team independently walked down the three EDGs and SBO/Appendix "R" DG on several occasions to inspect for indications of vibration-induced degradation on EDG piping and tubing and for any type of leakage (air, fuel oil, lube oil, jacket water). The team also directly observed the No. 21 EDG monthly surveillance run on July 21, 2009, and performed pre and post-run walkdowns to ensure Entergy maintained appropriate configuration control and identified deficiencies at a low threshold.

b. Findings

No findings of significance were identified.

.2.3.2 NRC Information Notice 2007-06: Potential Common Cause Vulnerabilities in Essential

Service Water Systems

a. Inspection Scope

The team evaluated Entergy's applicability review and disposition of NRC IN 2007-06.

The IN informed licensees of a potential common cause failure mechanism of SW systems due to external corrosion of piping that could lead to catastrophic failure. The team reviewed Entergy's evaluation of this issue. Specifically, the team reviewed corrective action documents, interviewed plant engineers, and walked down selected portions of the SW system, including the below grade SW pump pit and Zurn strainer pit, to verify Entergy had appropriately evaluated the OE.

b. Findings

No findings of significance were identified.

.2.3.3 NRC Information Notice 2006-31: Inadequate Fault Interrupting Rating of Breakers

a. Inspection Scope

The team reviewed Entergy's disposition of IN 2006-31. The IN discussed industry events and concerns associated with inadequate fault interrupting rating of breakers.

The team reviewed the disposition of the IN as documented by Entergy in CR-IP3-2007-01778 (the review was also applicable to IP2) and noted that engineering had concluded that design calculations and breaker ratings were adequate. The team reviewed the evaluation and the supporting short circuit analysis for IP2 and determined that Entergy had appropriately dispositioned this OE item.

b. Findings

No findings of significance were identified.

.2.3.4 NRC Information Notice 2005-30: Safe Shutdown Potentially Challenged by Unanalyzed Internal Flooding Events and Inadequate Design

a. Inspection Scope

The team reviewed Entergy's disposition of IN 2005-30. This IN discussed recent industry events where it was discovered that safe shutdown was potentially challenged by unanalyzed flooding events and inadequate design. The team reviewed the disposition of the IN as documented by Entergy in CR OEN-2005-00482, corrective action CA-9, for both units. In this CR, Entergy had discussed the evaluation of internal flooding for Units 2 and 3, and determined that the internal flooding issues discussed in IN 2005-30 had been previously evaluated, and concluded that there were no new or additional flooding scenarios associated with the IN. Entergy determined that the design was adequate and that no additional design modifications were required. The team reviewed corrective action documents, interviewed plant engineers, and walked down accessible portions of safety-related systems (e.g., RHR pump rooms, EDGs, electrical switchgear, AFW) looking for flood-related vulnerabilities to verify that Entergy had appropriately evaluated the OE.

b. Findings

No findings of significance were identified.

.2.3.5 NRC Information Notice 2008-09: Turbine-Driven Auxiliary Feedwater Pump Bearing Issues

a. Inspection Scope

The team evaluated Entergy's applicability review and disposition of NRC IN 2008-09. The NRC issued the IN to alert licensees to issues with TDAFW pumps, as they relate to the importance of having accurate maintenance instructions and effective post-maintenance tests (PMTs). Entergy concluded that their maintenance procedures and PMT practices were adequate. In particular, engineering determined that, in addition to PMTs, they monitor the bearing temperature and vibration of the pump every time the TDAFW pump is run, as well as take oil samples for analysis. The team reviewed maintenance procedures, corrective action documents and interviewed plant personnel to assess the adequacy of Entergy's testing and maintenance procedures with respect to monitoring TDAFW pump bearing performance. The team also conducted several detailed walkdowns to assess the material condition of the TDAFW pump and its support systems, and to ensure adequate configuration control.

b. Findings

No findings of significance were identified.

.2.3.6 NRC Information Notice 1995-10, Potential for Loss of Automatic Engineered Safety Features Actuation

a. Inspection Scope

The team evaluated Entergy's applicability review and disposition of NRC IN 95-10. The NRC issued the IN to alert licensees to potential design issues that could result in a fault on a non-safety circuit adversely impacting the power supply to the engineered safeguards actuation system. The team reviewed Entergy's associated evaluation, the ESFAS DBD, and ESFAS drawings and determined that Entergy had appropriately dispositioned this OE item.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA2 Identification and Resolution of Problems (IP 71152)

The team reviewed a sample of problems that Entergy had previously identified and entered into the CAP. The team reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions.

In addition, CRs written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problem into the CAP. The specific corrective action documents that were sampled and reviewed by the team are listed in the Attachment.

b. Findings

No findings of significance were identified.

4OA6 Meetings, including Exit

On August 13, 2009, the team presented the inspection results to Mr. Donald Mayer, Director, Unit 1 and Special Projects (Acting Site Vice President), Mr. Anthony Vitale, General Manager, Plant Operations, and other members of Entergy management. The team verified that no proprietary information is documented in the report.

ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Entergy Personnel

B. Altadonna, Program and Components Engineer
N. Azevedo, Engineering Programs
J. Balletta, Supervisor, Operations Support
T. Beasley, System Engineer
J. Bencivenga, Design Engineer
P. Bowe, Engineer, Civil Design
C. Bristol, Maintenance Engineer
P. Conroy, Director of Nuclear Safety Assurance
J. Coulter, Predictive Maintenance Engineer
K. Curley, System Engineer
G. Dahl, Specialist, Licensing
M. Dries, System Engineer
T. Gander, Operations Procedure Group
D. Gayner, PRA Engineer
C. Ingrassia, System Engineer
E. Kenney, AOV Program Engineer
C. Kocsis, Operations Training
M. Koutsakos, System Engineer
C. Laverde, Component Engineer
L. Liberatori, Design Engineer
D. Mayer, Director, Unit 1 and Special Projects
T. McCaffrey, Manager, Design Engineer
B. McCarthy, Operations Assistant Manager
V. Myers, Design Engineering Supervisor
R. Parks, EOP Coordinator
M. Radvansky, Design Engineer
H. Robinson, Design Engineer
R. Schimpf, Design Engineer
R. Sergi, Design Engineer
B. Shepard, I&C Design Engineer
J. Timone, Component Engineer
A. Vitale, General Manager, Plant Operations
R. Walpole, Licensing Manager
C. Wilson, System Engineer
A. Zografos, Design Engineer

Attachment

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Open and

Closed

05000247/FIN-2009007-01 NCV Failure to evaluate the impact on breaker coordination for the Westinghouse
Amptector type LSG trip unit discriminator

feature. (Section 1R21.2.1.1)

05000247/FIN-2009007-02 NCV Failure to ensure that the CCW pump hydraulic performance test procedures had

acceptance criteria that incorporated the

limits from applicable design documents.

(Section 1R21.2.1.2)

05000247/FIN-2009007-03 FIN Failure to identify several degraded city water system pipe supports in the utility

tunnel. (Section 1R21.2.2.1)

LIST OF DOCUMENTS REVIEWED

Audits and Self-Assessments

IP3LO-2009-00005, Component Design Bases Inspection for Indian Point 2 IPEC Focused Self-Assessment Report, dated 4/15/09

Calculations

18.03.F02.007, Air Operated Gate and Globe Valve Component Calculations, Rev. 0
41008.01, Control Room Panel Seismic Evaluation, Rev. 4
60817-2, 480V DB Circuit Breaker Setting for the 250HP Component Cooling Pump Motors,
2/17/86
60817-4, 480V DB Circuit Breaker Setting for the 400HP Residual Heat Removal Pump Motors, Rev. 1
CN-POE-01-05, SG Pressure EOP Setpoint Analysis, Rev. 3
ECX-00001, TOR Impedance Summary, Rev. 0
EGP-S36-002, EDG Building Ventilation System Upgrade Ampacity & Voltage Drop Calculations, Rev. 0
FEX-00141, IP2 Amptector Setting Verification, Sensor and Tolerances, Rev. 1
FEX-00143, IP2 Load Flow Analysis of the Electrical Distribution System, Rev. 1
FEX-00204, Station Battery 22 System Calculation, Rev. 1
FFX-00104, Check Minimum Line Size to Allow the City Water Header to Provide the Aux.
Feed Water Pumps with 800 GPM, Rev. 0
FIX-00024,
CST-Level Setpoints, Channel Accuracies and Corresponding Volumes, Rev. 3
FIX-00030, N2 Backup System Capacity to Support Critical AFW System Air Users in the Event of Loss of Instrument Air, Rev. 3
FIX-00035, RHR Indicated Flow and Flow Errors for EOP, Rev. 0
FIX-00145-00, Main Steam Pressure Loop Accuracy, Rev. 1
FMX-00085, RWST Minimum Submergence Level, Rev. 1
Attachment
FMX-00086, CST Critical Submergence at Varied Flow Rates, Rev. 1
FMX-00130, Impact of Pipe Break Downstream of
LCV-1158, Rev. 1
FMX-00162, Establish Stroke Time for Valve
LCV-1158, Rev. 0
FMX-00237, Verification of Aux Feed Pump Full Flow Test Acceptance Criteria, Rev. 0
FMX-000245, RHR Pump Available NPSH from Sump and RWST, Rev. 2
FMX-00275, Pipe Flow Analysis for AFW System, Rev. 1
FMX-00287, Verification of AF Pump Recirculation Flow Test Acceptance Criteria, Rev. 1
FMX-00297, NPSH Calculation for RHR Pumps with One Pump/Heat Exchanger in Service, Rev. 2
IP-CALC-04-00650, IP2 Aux Feedwater System Safety Valve Sizing
MS-52, Rev. 0
IP-CALC-04-01180, Attachment A, SQUG Panel Document, Rev. A
IP-CALC-05-01034, Appendix R Cooldown Benchmark and Sensitivity Analysis Using
RETRAN-3D, Rev. 1
IP-CALC-06-00026, Indian Point Unit 2 (IP2) Hydraulic Analysis of Recirculation and Containment Sump Strainers, Rev. 3
IP-CALC-06-00281, Ventilation System for EDG Building, Rev. 0
IP-CALC-08-00022, Analysis of IP2 SBO/APPR DG Supplying IP2 SBO Loads, Rev. 0
IP-RPT-08-00044, Study for the Impact of Bus Transfer Transients With 10-Cycle Dead-Time on the 480V Safety-Related Motor Performance for Indian Point 2 & 3, Rev. 0
MEX-00131, Evaluation of Generic Letter 95-07 Power Operated Valves for Pressure Locking and Thermal Binding, Rev. 4
PGI-00473, Motor Operated Valve Terminal Voltage; Altran Calculation No. 99621-C-002,
Rev. 3
PGI-00475,
GL-89-10 MOV Protection - TOR Settings, Rev. 2
PGI-00496, AOV System Calculation for STM
GEN 21 Atmospheric Dump Valves
PCV-1134,
1135, 1136, and 1137, Rev. 0
PGI-00497, Auxiliary Feedwater System Air Operated Valve Functional and Maximum Expected Differential Pressure Calculation, Rev. 1
PGI-00518, AOV Component Level Calculations for
FCV-405A,
FCV-405B,
FCV-405C, and
FCV-405D, Rev. 1
SCN-00026,
ESF-Safeguard Actuation Signal Response Time, Rev. 0
SGX-00005, Emergency Diesel Generator Building Ventilation Upgrade, Rev. 0
SGX-00007, 125V DC System Protection Device Coordination Study, Rev. 3
SGX-00051, 6900V Switchgear Coordination Calculation for Switchgear Buses 1, 2, 3, 4, 5

and 6, Rev. 1

SGX-00059, Safety Related 480V MCC Coordination Calculation for
MCC-26A, Rev. 1
SGX-00073, Bus Transfer (Transient) Analysis of the IP2 Electrical Distribution System, Rev. 1
SQUG Evaluation Sheet for EQID No. 0023EDJET, EDG No. 23 Jacket Water Expansion Tank dated 3/4/93 SQUG Evaluation Sheet for EQID No. PNL EPA77, EDG Vent Distribution Panel 1, dated 10/30/96 SQUG Evaluation Sheet for EQID No. PNL EPA78, EDG Vent Distribution Panel 2, dated 10/30/96
Attachment Completed Surveillance Test Procedures
2-PT-2M4, Safety Injection System Train "A" Actuation Logic and Master Relay Test, performed
5/18/09
2-PT-3Y010, Flow Test for Underground Service Water Line 409, performed 9/10/05
2-PT-M021A, Emergency Diesel Generator 21 Load Test, performed 4/1/09 & 5/28/09
2-PT-M021B, Emergency Diesel Generator 22 Load Test, performed 4/2/09 & 5/29/09
2-PT-M021C, Emergency Diesel Generator 23 Load Test, performed 3/31/09 & 5/28/09
2-PT-M110, Appendix R DG Functional Test, performed 1/17/09, 4/11/09 & 7/1/09
2-PT-Q013, Inservice Valve Tests, performed 4/23/09, 5/6/2009, 5/21/09 & 7/1/09
2-PT-Q013, Inservice Valve Tests -
MOV 535 & 536 Data Sheets, performed 1/18/09
2-PT-Q013-DS250, Valve
PCV-1136 IST Data Sheet, performed 4/17/08
2-PT-Q030A, 21 Component Cooling Water Pump, performed 3/18/09
2-PT-Q030B, 22 Component Cooling Water Pump, performed 5/12/09
2-PT-Q030C, 23 Component Cooling Water Pump, performed 4/16/09 & 7/9/09
2-PT-Q034, 22 Auxiliary Feed Pump, performed 4/23/09
2-PT-Q034A, 22 Auxiliary Feed Pump Steam Supply Valves, performed 6/12/09
2-PT-Q055, Pressurizer Pressure, performed 2/25/09 & 5/20/09
2-PT-Q058, Steam Generator Level Bistables, performed 3/18/09 & 6/11/09
2-PT-Q059, Containment Pressure Bistables, performed 3/10/09 & 6/5/09
2-PT-Q061, Main Steam Line Pressure Bistables, performed 1/27/09 & 4/23/09
2-PT-Q062, High Steam Flow and Turbine First Stage Pressure Bistables, performed 2/11/09 & 5/6/09 2-PT-Q063, Steam Flow/Feedwater Flow Mismatch Bistables, performed 1/6/09 & 3/31/09
2-PT-Q280A, 21 Residual Heat Removal Pump, performed 3/9/09 & 6/1/09
2-PT-Q280B, 22 Residual Heat Removal Pump, performed 3/26/09
2-PT-R013, Safety Injection System, performed 3/28/08
2-PT-R013B, Auxiliary Feedwater Pumps Automatic Actuation Circuitry, performed 3/27/08
2-PT-R014, Automatic Safety Injection System Electrical Load and Blackout Test, performed
4/22/06 & 3/28/08
2-PT-R022A, Steam Driven Auxiliary Feed Pump Full Flow, performed 3/21/08
2-PT-R062, Pressurizer PORVs, performed 4/10/08
2-PT-R083, AMSAC End-to-End Functional, performed 4/18/08
2-PT-R139, RHR Pumps, Flow Settings, and Check Valves, performed 3/29/08
2-PT-SA069, City Water Backup Cooling Flow Test, performed 11/13/06, 5/3/07, & 4/2/09
2-PT-V008A, 22 ABFPT Mechanical Overspeed Alternate Trip Test, performed 4/4/08
2-PT-V014, Overpressurization Protection System Analog Channels, performed 3/24/08
2-PT-V015, Overpressurization Protection System Logic Check, performed 3/24/08
2-PT-V024E, Main Steam Isolation Valves, performed 10/6/05, 3/18/08, & 4/19/08
2-PT-V064, Auto Transfer Verification of Offsite Power for 6.9KV Buses 2 and 3, performed
4/18/06 & 3/23/08
2-PT-W010, Weekly Battery Surveillance Requirement, performed 1/21/09
Attachment

Condition Reports

(CR-IP2-)

1998-10046
2003-0860
2003-2511
2004-1445
2005-0772
2005-1401
2005-0374
2005-3027
2005-3223
2005-3576
2005-3984
2006-1970
2006-2020
2006-2256
2006-3224
2006-3691
2006-4678
2006-5017
2006-5208
2006-5241
2006-5422
2006-6511
2006-6867
2007-0219 2007-0980 2007-1046
2007-1442
2007-1779
2007-2189
2007-3141
2007-3295
2007-3825
2007-4164
2007-4174
2008-0002
2008-0668
2008-1021
2008-1342
2008-1414
2008-1421
2008-1471
2008-1482
2008-2023
2008-2125
2008-2229
2008-2447
2008-2710
2008-3264 2008-3476 2008-3869
2008-3889
2008-3901
2008-4230
2008-5047
2008-5212
2008-5499
2009-0099
2009-0245
2009-0339
2009-0340
2009-0341
2009-0346
2009-0462
2009-0681
2009-0758
2009-0805
2009-0820
2009-0868
2009-0978
2009-1245
2009-1473
2009-2085 2009-2112 2009-2773*
2009-2796*
2009-2799*
2009-2824*
2009-2828*
2009-2829*
2009-2838*
2009-2841
2009-2848*
2009-2850*
2009-2857
2009-2858*
2009-2861*
2009-2862*
2009-2863*
2009-2865*
2009-2866*
2009-2907
2009-2912*
2009-2917*
2009-2945*
2009-2982
2009-2999* 2009-3006* 2009-3015*
2009-3016*
2009-3017*
2009-3033*
2009-3036*
2009-3046*
2009-3050*
2009-3065*
2009-3077*
2009-3081*
2009-3083*
2009-3084*
2009-3085*
2009-3086*
2009-3087*
2009-3091*
2009-3142*
2009-3143*
2009-3150*
2009-3156*
2009-3249*
2009-3301*
  • CR written as a result of this inspection
Design & Licensing Bases ConEdison Letter No.
NL-81-136, Response to
GL 81-14 Regarding Seismic Qualification of AFW System, dated 8/7/81 ConEdison Letter No.
NL-85-A21, Response to NRC on Seismic Qualification of AFW Components, dated 2/4/85
IP2-480V DBD, 480 Volt Electrical System Design Basis Document, Rev. 1
IP2-AFW DBD, Auxiliary Feedwater System Design Basis Document, Rev. 1
IP2-CCWS DBD, Component Cooling Water System Design Basis Document, Rev. 1
IP2-EDG DBD, Emergency Diesel Generator Design Basis Document, Rev.2
IP2-ESF-DBD, Engineered Safeguards Features System Design Basis Document, Rev. 1
IP2-MS DBD, Main Steam System Design Basis Document, Rev. 1
IP2-RCS/SG DBD, Reactor Coolant System/Steam Generator Design Basis Document, Rev. 1
Letter from Murray Seiman, Consolidated Edison, to USNRC, Loss of RHR while the RCS is Partially Filled, dated 9/29/87 Letter from Stephen B. Bram to USNRC, Supplemental Response to NRC Bulletin 88-04 Potential Safety Related Pump Loss, dated 7/19/88
NL-09-031, IPEC Letter to the NRC, Request for Exemption from 10
CFR 50, Appendix R, Paragraph
III.G.2 for Use of Operator Manual Actions for Indian Point Unit No. 2, dated 3/6/09
Attachment
NRC Letter to Entergy Nuclear Operations, Indian Point Nuclear Generating Unit No. 2
Issuance of Amendment RE: 3.26 Percent Power Uprate (TAC No. MC1865), dated 10/27/04
Safety Evaluation Report, Susceptibility of Safety-Related Systems to Flooding from Failure of Non-Category I Systems for IP2, November 1980

Drawings

179950, Copes-Vulcan Model D-100, 6 Inch, Class 6000 Valve Assembly Tandem Trim 3

rd Generation, Rev. 4

193183, Unit 1 Piping Flow Diagram City Water System, Rev. 29
208485, 28 Inch OD Pipe Main Steam Stop Valve, Rev. 8
2688, Flow Diagram Instrument Air Containment Building & Auxiliary Boiler Feed Pump;
Building, Rev. 27
251132, AFW Flow Control Loop, Rev. 6
251231, AFW Steam Supply to Auxiliary Feed Water Pump 22, Rev. 5
2422, CVCS Loop Diagram for RCP Instrumentation, Rev. 3
263935, 125VDC Power Panel #21 Circuit Assignment, Rev. 0
263936, 125VDC Power Panel #22 Circuit Assignments, Rev. 1
306641-01, W/D of Temperature Controller in Station Service Transformer #5, Rev. 1
311906,
SOV 455C Pressurizer PORV
PCV-455C, Rev. 1
311907,
SOV 456 Pressurizer PORV
PCV-456, Rev. 1
360858, Copes-Vulcan Series D-1000 Valve Assembly Class 900, Rev. 0
400882, Station Blackout and Appendix R Diesel Generator Set P&ID Diesel Cooling Water System Mechanical, Rev. 0
709091 Sh. 1, Auxiliary Feedwater Control Globe Valve, Rev. 1
21-F-2017 Sh. 2, Flow Diagram Main Steam, Rev. 84
21-F-2018, Flow Diagram Condensate and Boiler Feed Pump Suction, Rev. 143
21-F-2019, Flow Diagram Boiler Feedwater, Rev. 114
21-F-2028, Flow Diagram Jacket Water to Diesel Generator, Rev. 36
21-F-2030, Flow Diagram Fuel Oil to Diesel Generator, Rev. 39
21-F-2036, Flow Diagram Instrument Air Control Building Conventional Plant, Rev. 98
21-F-2593, PAB Composite Piping at Charging Pumps, Rev. 40
21-F-2696, PAB Service Air, City Water & Drains, Rev. 35
21-F-2720, Flow Diagram Auxiliary Coolant System, Rev. 89
21-F-2729, SG Blowdown & Blowdown Sample System Flow Diagram, Rev. 69
21-F-2736, UFSAR Figure 9.2-1 SHT 1 - CVCS Flow Diagram, Rev. 128
21-F-3006, Single Line Diagram 480V MCC26A and 26B, Rev. 94 & 95
21-F-3204, 125 VDC Power Panels 21 & 22 Wiring Diagram, Rev. 76
21-LL-3113 Sh. 1, Schematic Diagram - 6900V Switchgear 21, Rev. 14
21-LL-3113 Sh. 3, Schematic Diagram - Breaker 52/UT1-ST5 Bus #1 Tie, Rev. 14
21-LL-3113 Sh. 4, Schematic Diagram - Breaker 52/UT2 Bus 2, Rev. 10
21-LL-3113 Sh. 5, Schematic Diagram - Breaker 52/UT2-ST5 Bus 2-5 Tie, Rev. 10
21-LL-3113 Sh. 7, Schematic Diagram - Breaker 52/RCP21 Reactor Coolant Pump 21, Rev. 16 9321-LL-3113-10 Sh. 16, Schematic Diagram - 6900V Bus 1,2, & 5 Lockout Relays

(86/UT1, 86/UT2, & 86/ST5), Rev. 10

21-LL-3130 Sh. 5, Generator Primary Lockout Relay 86P, Rev. 31
21-LL-3130 Sh. 6, Generator Backup Lockout Relay 86BU, Rev. 38
Attachment
21-LL-3131 Sh. 8, AFW Logic Schematic, Rev. 10
21-LL-3132 Sh. 5, Schematic Diagram - Pilot Wire and Misc. Lock-Out Relays, Rev. 11
21-LL-3601 Sh. 3, Feedwater Bypass Valves Schematic, Rev. 10
21-LL-3601 Sh. 17, Feedwater Bypass Valves Schematic, Rev. 12
A207698, Lube Oil for Diesel Generators, Rev. 26
A208088, One Line Diagram 480VAC Swgrs. 21 & 22, Bus 2A, 3A, 5A & 6A, Rev. 43
A208168, UFSAR Figure 9.2-1 SHT 2 - CVCS Flow Diagram, Rev. 53
A208377, Main One Line Diagram, Rev. 12
A208500, One Line Diagram for 480VAC
MCC-26AA and MCC26BB &120VAC Distribution Panels 1&2, Rev. 45 A225016, Safeguards Actuation Schemes - Train A, Rev. 12
A225018, Safeguards Actuation Schemes - Train B, Rev. 10
A225096, Turbine Trip Signals Logic Diagram, Rev. 19
A225097, 6900V Bus Auto Transfer Logic Diagram, Rev. 5
A225101, Safeguards Sequence Logic Diagram, Rev. 11
A225102, Pressurizer Trip Signals Logic Diagram, Rev. 5
A225105, Safeguards Actuation Signals Logic Diagram, Rev. 10
A225106, Feedwater Isolation Logic Diagram, Rev. 7
A227781, Flow Diagram - Auxiliary Coolant System, Rev. 81
A231592, 6900 Volt AC One Line Diagram, Rev. 19
A235296, Flow Diagram Safety Injection System, Rev. 69
A250907, Electrical Transmission and Distribution System, Rev. 21
A251783, Flow Diagram Auxiliary Coolant System Residual Heat Removal System, Rev. 29
AAA00738, 45 Actuator 2 Body, 657 HPT Diaphragm Actuated Control Valve for
FCV-405A, 405B, 405C, and 405D, Rev. A B192505 Sh. 1, Piping Flow Diagram City Water System, Rev. 19
B192506 Sh. 2, Piping Flow Diagram City Water System, Rev. 40
B243683, Diesel Generator Ventilation System Details, Rev. 3
D252276, SIS Recirculation Flow Loop #640, #946, Rev. 5
IP2-S-000209, Pressurizer Power Relief Line Block Valve 535, Rev. 8
IP2-S-000210, Pressurizer Power Relief Line Block Valve 536, Rev. 8
IP2-S-000231, One-Line Schematic for EDG Building Ventilation Dist. Panels #1 & #2, Rev. 4
IP2-S-000291, EDG Exhaust Fan #318, Rev. 3
IP2-S-000346, Install of 6

th EDG Exh Fan - Swd, Rev. 2

Engineering Evaluations
04-001147, Procurement Engineering Technical Evaluation, Rev. 3
CR-IP2-2006-03691
CA-00002, Emergency Diesel Generator No. 21 Failed
PT-M21A Apparent; Cause Evaluation, dated 7/19/06
CR-IP2-2009-0978, Operability Evaluation for
PCV-1136, dated 3/12/09
CR-IP2-2008-1021, Apparent Cause Evaluation for MSIV
MS-1-22, dated 3/24/08
EEN-04-0108, Item Equivalency Evaluation, Rev. 4
FMA07P0520, Failure Mode Analysis Report of Non-Safety Related Foxboro Power Supply for Entergy Nuclear Northeast - Indian Point 2, dated 3/13/07
Attachment
IP-RPT-06-00022, Model 93 RCP Buffer Volume Related to Safe Shutdown Analysis, Rev. 0
Technical Report No. 00263-TR-001, Functionality and Risk Significance Evaluation of the Indian Point Unit 1 and 2 Mechanical and Electrical Systems Located in the Utility Tunnel, dated March 2001
Technical Report No. 92155-TR-01, Structural Assessment of 600,000 Gallon Condensate
Storage Tank, September 1992
Maintenance Work Orders
00126023
00141067
00141663
00145034
00148522
00152728
00171798
01-22289
2-21968
2-31082
2-32011 02-32013 02-33308
03-11725
03-31379
03-31474
03-31478
06-23642
251428
287272
295645
296260
51311792
51319252
51323098
51557019
51567240
51679124
51681055
51686249
51692345
51697357
2037044
IP2-01-22271
IP2-03-20310
IP2-03-25125
IP2-03-25169
IP2-03-25176
IP2-04-17932
IP2-04-31352
IP2-04-32996
IP2-06-18008

Miscellaneous

16" City Water Pipe - Flow Test, performed 5/26/09
1P-RPT-05-00138, IPEC Unit 2 and Unit 3 AOV Scoping and Categorization Report, Rev. 0
ANSI C50.41-2000, American National Standard for Polyphase Induction Motors for Power Generating Stations to
IPP-98-526, Draft Uncertainties for RHR and Containment Recirculation Flow Functions, February 1998
CCW Certified No. 22 Pump Curve, IR No. N-1402, dated 2/15/91
ConEdison Order No.
4900092, Performance & Thrust Test Report 8x20 W, Ingersoll-Dresser Pump Co., dated 1/20/95
CR-HQN-2007-00521
Cummins Metropower Inc. Letter, Quote No. 2004044b, IP2 SBO and Appendix R
Diesel Generator Set, dated 05/14/04
DRN-04-02623, Procedure 2-PT-Q030C change from Rev. 9 to Rev. 10, dated 9/8/04
EC No.
5000034211, RHR Pump Room Flooding, September 2008
ENN-EE-S-010-IP2, Electrical Separation Design Criteria, Rev. 2
ENS-I&C-DC, Power Supply PM Basis Template, Rev. 2
EPRI
EL-4286, Improved Motors for Utility Applications Volume 2: Bus Transfer Studies, October 1986
EPRI
NP-7412R1s, EPRI Air-Operated Valve Maintenance Guide, dated 11/96
Ingersoll-Dresser Pumps, Pump 8 x 20w, Residual Heat Removal Pump Curve, dated 11/23/94
IP2-05-13447, Replace Westinghouse Type REH Breakers in DPBL 22, Rev. 0
IP2-9412, Operations Document Feedback Form for 2-PT-M110, dated 7/28/09
IP2-9437, Operations Document Feedback Form for EOP E-3 Step 2, dated 8/12/09
IP2-UT-09-036, 180 Day Follow-up Exam of various SW Piping Weld Leaks, dated 8/7/09
IR-RPT-04-00230, Internal Flooding Analysis Notebook, Appendix C, Rev. 1
LER 2007-004-00, Manual Reactor Trip Due to Decreasing Steam Generator Levels Caused by Loss of Feedwater Flow as a Result of Feedwater Pump Suction Pressure Transmitter Power Supply Failure, dated 4/30/07
Attachment Letter from R. Laubham, Westinghouse, to Dave Morris, Entergy, Condensate Storage Tank Minimum Usable Inventory, dated 6/16/04 Log Entries Report, dated 7/10/09 - 7/20/09
LO-NOE-2005-01008
LO-NOE-2007-00427
Maintenance Rule Basis Document City Water System (CYW), Rev. 2
MPR Associates Trip Report, Support AVR Card Inspection Following Part 21 Notice for EDG
31, 32 and 33, dated 3/17/09, 3/27/09, & 4/13/09
MPR Report No. 1051, Report of Operability Tests of RHR Pumps at Reduced Reactor Coolant System Levels, February 1988
N-1402, Component Cooling Water Pump Curve, dated 02/20/81
NL-85-286-C01, NRC Commitment Regarding AFW Seismic Qualification, dated 12/26/85
NL-85-286-C02, NRC Commitment Regarding AFW Seismic Qualification, dated 12/26/85
RHR Certified No. 22 Pump Curve, IR No. 4688, dated 5/12/67
Rover Rounds, dated 7/9/09 - 7/19/09
TDAFW Certified No. 22 Pump Curve, Worthington No. E-216435, dated 4/22/87
Top Ten Action Plan - IPEC Power Supply PMs, Rev. 4
Westinghouse Letter
SEE-00-157, IP2 Restart Assessment-RHR Pump NPSH Evaluation
During Recirculation, dated 12/20/00 Westinghouse Letter
SEE-03-73, Rev. 1, Indian Point Unit 2-Stretch Power Uprate Project Report for NSSS Systems, dated 11/26/03
Westinghouse Report No.
WCAP-12312, Safety Evaluation for an Ultimate Heat Sink Temperature of 95º F at Indian Point Unit 2, January 2004
WOG ERG LE3, Steam Generator Tube Rupture,
LP-Rev. 2
Normal and Special (Abnormal) Operations Procedures
2-AOP-CCW-1, Loss of Component Cooling Water, Rev. 1
2-AOP-CVCS-1, Chemical and Volume Control System Malfunctions, Rev. 5
2-AOP-RCP-1, Reactor Coolant Pump Malfunction, Rev. 8
2-AOP-SSD-1, Att. 10, Backup Cooling Water Supply to Charging Pumps, Rev. 13
2-ARP-003, Diesel Generator, Rev. 3
2-ARP-SCF 2-3, Condensate Storage Tank Low Level, Rev. 41
2-ARP-SFF 3-5, RCP Thermal Barrier Low Delta-P, Rev. 26
2-ARP-SHF (2-10), 6900 V Bus Transfer Block, Rev. 29
2-ARP-SHF (4-7), Motor Control Center 26A, 26B and 26C - 52/MCC 26A-26B-26C Auto Trip, Rev. 29
2-E-0, Reactor Trip or Safety Injection, Rev. 1
2-E-0 BG, Reactor Trip or Safety Injection Background Document, Rev. 0
2-E-1, Loss of Reactor or Secondary Coolant, Rev. 0
2-E-1 BG, Loss of Reactor or Secondary Coolant Background Document, Rev. 0
2-E-3, Steam Generator Tube Rupture, Rev. 0
2-E-3 BG, Steam Generator Tube Rupture Background Document, Rev. 0
2-E-3 DEV, E-3 EOP Deviation Document, Rev. 0
2-ECA-1.1, Loss of Emergency Coolant Recirculation, Rev. 0
2-ES-0.1, Reactor Trip Response, Rev. 2
2-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 2
2-FR-C.1, Response to Inadequate Core Cooling, Rev. 0
2-FR-C.1 BG, Response to Inadequate Core Cooling Background Document, Rev. 0
Attachment
2-FR-H.1, Response to Loss of Secondary Heat Sink, Rev. 3
2-FR-H.1 BG, Response to Loss of Secondary Heat Sink Background Document, Rev. 0
2-SOP-1.4.1, Overpressure Protective System (OPS) Operation, Rev. 19
2-SOP-4.1.2, Component Cooling System operation, Rev. 35
2-SOP-4.2.2, Operation With Reduced RCS Inventory, Rev. 20
2-SOP-27.1.4, 6900 Volt System, Rev. 27
2-SOP-27.3.1.1, 21 Emergency Diesel Generator Manual Operation, Rev. 19
SOP 27.3.2, Filling Diesel Fuel Oil Storage, Rev. 21
2-SOP-27.6, Appendix-R Diesel Generator Operation, Rev. 6
2-SOP-AFW-002, Auxiliary Feedwater System Support Procedure, Rev. 1
2-SOP-ESP-001, Local Equipment Operation and Contingency Actions, Rev. 4

Operating Experience

LO-NOE-2007-00078, IP2 Review of NRC
IN 2007-06, dated 4/30/07
NRC Information Notice 92-29, Potential Breaker Miscoordination Caused By Instantaneous
Trip Circuitry, dated 4/17/92
NRC Information Notice 94-33: Capacitor Failure in Westinghouse Eagle 21 Plant Protection Systems, dated 5/9/94
NRC Information Notice 98-43, Leaks in the Emergency Diesel Generator Lubricating Oil and
Jacket Cooling Water Piping, dated 12/4/98
NRC Information Notice 2005-14, Loss of Seal Cooling to Westinghouse RCPs, dated 6/1/05 NRC Information Notice 2005-30, Safe Shutdown Potentially Challenged by Unanalyzed Internal Flooding Events and Inadequate Design, dated 11/7/05 NRC Information Notice 2008-09, Turbine-Driven AFW Pump Bearing Issues, dated 5/22/2008
NRC Information Notice 2007-06, Potential Common Cause Vulnerabilities in Essential Service Water Systems, dated 2/9/07 NRC Information Notice 2009-02, Biodiesel in Fuel Oil Could Adversely Impact Diesel Engine Performance, dated 2/23/09
NRC Information Notice 2009-10, Transformer Failures - Recent Operating Experience, dated 7/7/09 Westinghouse
TB-04-22, RCP Seal Performance, Rev. 1
Westinghouse
WCAP-16755P, Operator Time Critical Action Program Standard, Rev. 0
Operator Training
I2SG-LOR-EOP009, Response to SGTR, E-3, and
ES-3 Lesson Plan, Rev. 1
JPM 0590080404, Replace 21 Feedwater Regulating Valve Air Lines for Local Operation, dated 8/22/07
JPM 0060020404, Establish Backup Cooling to SI Pumps, dated 3/1/06
JPM 0060020404, Lineup City Water to SI and RHR Pumps with Pumps Running, dated 3/1/06
JPM 0840010402, Establish Backup Cooling to Charging Pumps, dated 3/1/06
JPM 0840041624-1, Lineup City Water to SI and RHR Pumps with Pumps Shutdown, dated 3/1/06
LEQ-SES-35, Steam Generator Tube Rupture Simulator Scenario, Rev. 1
Attachment Preventive Maintenance
0-ELC-403-BUS, Inspection and Cleaning of 480 Volt Bus Duct, performed 11/7/04 & 4/5/08
0-GNR-403-ELC, Emergency Diesel Generator Quarterly Inspection, performed 7/21/09
0-LUB-401-GEN, Lubrication of Plant Equipment, performed 1/29/09 0-VLV-404-AOV, Use of Air Operated Valve Diagnostics, performed 11/1/04, 11/13/04, 11/18/04, & 2/25/09 0-VLV-415-VCK, Main Steam Valve Overhaul and Replacement, performed 4/11/08
3-IC-PC-I-Y-1103, Auxiliary Feed Pump No. 32 Tachometer, performed 11/5/08
51768428-01, 3M Insp Xfmr Station Service Transformer 5A Clg Sys, Clean and Manual Test Fans, performed 11/3/06 & 3/9/09
2027372-01, 3M Insp Xfmr Station Service Transformer 5A Clg Sys, Clean and Manual Test Fans, performed 3/9/09
AOV-B-011-A, Copes Vulcan Air Operated Atmospheric Steam Dump Valves Maintenance Procedure, performed 11/14/04 & 11/13/04
IP2-02-61376, 4Y Cal 6.9kV Bus Section 5, SST5 Relay, performed 11/6/06
IP2-04-24880, 2-BRK-023-ELC and 2-BRK-024-ELC for Breaker 52/6B, performed 3/18/06 &
3/20/06
IP2-05-13447, Replace Westinghouse Type REH Breakers in DPBL 22, performed 5/4/06
O-EDG-407-ELC, Emergency and Appendix "R" Diesel Generator Engine Analysis/Inspection, performed 7/21/09
PMS-B-002-A, Worthington (#22) Auxiliary Boiler Feed Pump Turbine 10 Year Dismantle Inspection, performed 9/24/02
VMS-B-002-A, Valve Repacking Using Graphite Packing and/or Live Load, performed 11/12/04

Procedures

0-BKR-406-ELC, Westinghouse 6900 Volt Breaker Inspection and Cleaning, Rev. 11
0-PNL-401-ELC, Distribution Panel and Breaker Maintenance and Inspection, Rev. 3
0-TUR-403-AFP, Worthington Auxiliary Boiler Feed Pump Turbine Preventive Maintenance, Rev. 4 0-VLV-403-AOV, Copes-Vulcan Model D-100 and D-1000 Air Operated Valves with Quick Change Trim, Rev. 1
0-XFR-401-ELC, Station Service and Load Center Transformers Outage Inspection, Rev. 0
2-ARP-SCF, Condensate and Boiler Feed, Rev. 41
2-BRK-023-ELC, DB Breaker Amptector/Westector Overcurrent Test, Rev. 4
2-BRK-024-ELC, DB Breaker Amptector/Westector Calibration Test, Rev. 1
2-COL-29.2, Instrument Air System, Rev. 29
2-MCC-001-ELC, Westinghouse Type W-480 Volt Motor Control Center Preventive Maintenance, Rev. 3
2-PT-M110, Appendix R DG Functional Test, Rev. 2
EN-DC-140, Air operated Valve Program, Rev. 1
EN-LI-102, Corrective Action Process, Rev. 13
MS-104, IP Unit #2 Maintenance Standard Inspection and Cleaning of Bus Bars, Contacts, Ground Connections, Wiring and Insulators, Rev. 2
OAP-008, Severe Weather Preparations, Rev. 6
OAP-012, EOP Users Guide, Rev. 5
OAP-017, Plant Surveillance and Operator Rounds, Rev. 6
OAP-038, Operations Mechanical Equipment Operating Guidelines, Rev. 3
Attachment
OAP-115 Att. 5, Time Critical Operator Actions, Rev. 9
PT-Q13, Inservice Valve Test Data Sheet No. 94, Rev. 23
PT-R35, Inservice Valve Tests, Rev. 11
SEP-SW-001,
GL 89-13 Service Water Program, Rev. 1
Risk and Margin Management
IP-RPT-04-00230, Indian Point Unit Two Probabilistic Safety Assessment (PSA), Rev. 1
IP-RPT-04-00230 App. H, Human Reliability Analysis, Rev. 1
PD-95-034, Individual Plant Examination of External Events for Indian Point 2, December 1995
Risk-Informed Inspection Notebook for Indian Point Nuclear Generating Station, Rev. 2.1a
System Health Reports & Trending
AFP Turbine Outboard and Inboard Bearing Lube Oil Samples, 2004-2008
6.9kV System Health Report, 1st Quarter 2009
480V System Health Report, 1st Quarter 2009
AFW System Health Report, 1st Quarter 2009
AOV Program Health Report, 2nd Quarter 2009
CCW System Health Report, 1st Quarter 2009
EDG System Health Report, 1st Quarter 2009
Engineered Safeguards Initiation Logic System Health Report, 1st Quarter 2009
IP-2 Reliability - CYW System, dated August 2007 - June 2009
Main Steam System Health Report, 1st Quarter 2009
RHR System Health Report, 1st Quarter 2009
Service Water NDE RT & UT Test Results Report for Zurn Strainer Pit, 1992 to July 2009
Station Diesels Annual Health Report, 2007 & 2008
Vendor Technical Manuals
01:P13:37, Instruction Manual for Diaphragm Operated Copes-Vulcan Control Valves, Rev. 4
1766, Atwood & Morrill Instruction Manual Main Steam Isolation and Main System Check Valves, Rev.2
2404, Copes Vulcan,
PCV-1139 Installation, Operation & Maintenance Instruction, Rev. 0
22, Westinghouse Air Circuit Breaker Type DH, Rev. n/a
I.B.
WCR-5815, Westinghouse Instruction Book Type ASL Core Form Power Center Transformer, S.O. 24-Y-4800-1, dated 10/67 Westinghouse Transformers Test Report (for Station Service Transformer #5), dated 10/26/67
Worthington Manual No. W-9C, Worthington Single Stage Steam Turbine Instructions, Rev. 2
Attachment

LIST OF ACRONYMS

AC Alternating Current
ADAMS Agency-Wide Documents Access and Management System
AFW Auxiliary Feedwater
AOP Abnormal Operating Procedure
AOV Air Operated Valve
ASME American Society of Mechanical Engineers
CA Corrective Action
CAP Corrective Action Program
CCW Component Cooling Water
CDBI Component Design Bases Inspection
CFR Code of Federal Regulations
CR Condition Report
CST Condensate Storage Tank
CVCS Chemical and Volume Control System
DBD Design Basis Document
DC Direct Current
DG Diesel Generator
DRS Division of Reactor Safety
EDG Emergency Diesel Generator
EOP Emergency Operating Procedure
EPRI Electric Power Research Institute
ERG [[[WOG] Emergency Response Guideline]]
ESF Engineered Safeguards Feature
ESFAS Engineered Safeguards Features Actuation System
GL Generic Letter
GPM Gallons Per Minute
IMC Inspection Manual Chapter
IN Information Notice
IP Inspection Procedure
IPEC Indian Point Energy Center
IST In-Service Test
JPM Job Performance Measure
KV Kilo Volts
LER Licensee Event Report
LSG Long, Short, & Ground
LSIG Long, Short, Instantaneous, & Ground
LTOP Low Temperature Overpressure Protection
MCC Motor Control Center
MOV Motor Operated Valve
MR Maintenance Rule
NCV Non-Cited Violation
NDE Non-Destructive Examination
NPSH Net Positive Suction Head

NRC Nuclear Regulatory Commission

OE Operating Experience

OpESS Operating Experience Smart Sample

Attachment

P&ID Piping and Instrument Diagram
PAB Primary Auxiliary Building
PARS Publicly Available Records
PM Preventive Maintenance
PMT Post Maintenance Test
PORV Power Operated Relief Valve
PSA Probabilistic Safety Assessment
RAW Risk Achievement Worth
RCP Reactor Coolant Pump
RCS Reactor Coolant System
RHR Residual Heat Removal
RRW Risk Reduction Worth
RT Radiographic Test
RWST Refueling Water Storage Tank
SBO Station Blackout
SDP Significance Determination Process
SG Steam Generator
SGTR Steam Generator Tube Rupture
SI Safety Injection
SPAR Standardized Plant Analysis Risk
SQUG Seismic Qualification Utility Group
SW Service Water
TDAFW Turbine Driven Auxiliary Feedwater
TDH Total Developed Head
TRM Technical Requirements Manual
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
UT Ultrasonic Test
VAC Volts Alternating Current
WOG Westinghouse Owners Group
Retrieved from "https://kanterella.com/w/index.php?title=IR_05000247/2009007&oldid=978813"