IR 05000220/2007002

Download: ML071200236

Text

April 27, 2007

Mr. Kevin J. NietmannActing Vice President Nine Mile Point Nine Mile Point Nuclear Station, LLC P.O. Box 63 Lycoming, NY 13093

SUBJECT: NINE MILE POINT NUCLEAR STATION - NRC INTEGRATED INSPECTIONREPORT 05000220/2007002 and 05000410/2007002

Dear Mr. Nietmann:

On March 31, 2007, the US Nuclear Regulatory Commission (NRC) completed an inspection atyour Nine Mile Point Nuclear Power Plant Unit 1 and Unit 2. The enclosed inspection report documents the inspection results discussed on April 20, 2007, with Mr. Mark Schimmel and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.This report documents one finding of very low safety significance (Green). The finding wasdetermined to involve a violation of NRC requirements. However, because of its very low safety significance and because it was entered into your corrective action program (CAP), the NRC is treating this violation as a non-cited violation (NCV) in accordance with Section VI.A.1 of the NRC's Enforcement Policy. If you contest the NCV in this report, you should provide a response with the basis for your denial, within 30 days of the date of this inspection report, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C.

20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-001; and the NRC Resident Inspector at Nine Mile Point.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure, and your response (if any) will be available electronically for public inspection in the K. Nietmann2NRC Public Document Room or from the Publicly Available Records (PARS) component of theNRC'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/Blake D. Welling, Acting ChiefProjects Branch 1 Division of Reactor ProjectsDocket No.:50-220, 50-410License No.: DPR-63, NPF-69

Enclosure:

Inspection Report 05000220/2007002 and 05000410/2007002

w/Attachment:

Supplemental Informationcc w/encl:M. J. Wallace, President, Constellation Generation J.M. Heffley, Senior Vice President and Chief Nuclear Officer C. W. Fleming, Esquire, Senior Counsel, Constellation Energy Group, LLC M. J. Wetterhahn, Esquire, Winston and Strawn P. Smith, President, New York State Energy, Research, and Development Authority J. Spath, Program Director, New York State Energy Research and Development Authority P. D. Eddy, Electric Division, NYS Department of Public Service C. Donaldson, Esquire, Assistant Attorney General, New York Department of Law Supervisor, Town of Scriba T. Judson, Central NY Citizens Awareness Network D. Katz, Citizens Awareness Network

SUMMARY OF FINDINGS

...................................................iii

REPORT DETAILS

..........................................................1

REACTOR SAFETY

.........................................................11R01Adverse Weather Protection .......................................1

1R23 Temporary Plant Modifications ....................................14

1EP6Drill Evaluation

OTHER ACTIVITIES

........................................................154OA2Identification and Resolution of Problems............................154OA3Event Followup ................................................15 4OA5Other Activities.................................................16 4OA6Meetings, Including Exit..........................................17ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

................................................A-1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

...........................A-1

LIST OF DOCUMENTS REVIEWED

..........................................A-1

LIST OF ACRONYMS

.....................................................A-10

iiiSUMMARY

OF [[]]

FINDINGSIR 05000220/2007002, 05000410/2007002; 01/01/2007-03/31/2007; Nine Mile Point, Units 1and 2; Surveillance Testing.The report covered a thirteen-week period of inspection by resident and region-basedinspectors. One Green NCV was identified. The significance of most findings is indicated by

their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,

"Significance Determination Process." Findings for which the significance determination

process 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

NUR [[]]

EG-1649, "Reactor Oversight Process," Revision 4, dated

December 2006.

A.NRC -Identified and Self-Revealing FindingsCornerstone: Mitigating Systems*Green. A self-revealing, non-cited violation (

NCV) of technical specification (TS)5.4, "Procedures," was identified on January 11, 2007, when the Unit 2 reactor

core isolation cooling (RCIC) system automatically isolated as a result of an

improperly performed surveillance procedure. When performing a test of the

temperature instrument that provides residual heat removal (RHR) and

RC [[]]

IC

system high area temperature isolations, technicians failed to ensure that the

affected channel was bypassed prior to disconnecting the input thermocouple.

This resulted in an automatic isolation of the

RC [[]]

IC system steam supply and the

unavailability of

RC [[]]

IC for approximately four hours. Operators immediately

recognized the error and halted the surveillance procedure. Technicians

reconnected the thermocouple, and operators restored

RC [[]]

IC to a normal

standby lineup.

NMPNS entered the issue into the

CAP as condition report (CR)

2007-0186.The finding is greater than minor because it is associated with the humanperformance attribute of the Mitigating Systems cornerstone and affected the

cornerstone objective to ensure the availability, reliability, and capability of

systems that respond to initiating events to prevent undesirable consequences.

The finding is of very low safety significance in accordance with IMC 0609,

Appendix AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., "Determining the Significance of Reactor Inspection Findings for

At-Power Situations," based on a Phase 3 analysis. The Region I senior reactor

analyst (SRA) used the Nine Mile Point Unit 2 Standardized Plant Analysis Risk

(SPAR) model and the actual four-hour exposure time to determine that the

increase in core damage frequency was in the range of one core damage

accident in 125,000,000 years of reactor operation, high E-9 per year. This

finding has a cross-cutting aspect in the area of human performance because

the technicians failed to use appropriate human error prevention techniques,

such as self-checking and prominent visual identification of critical procedure

steps. (Section 1R22) B.Licensee-Identified ViolationsNone.

EnclosureREPORT

DETAIL [[]]

SSummary of Plant StatusNine Mile Point Unit 1 (Unit 1) began the inspection period at 100 percent power. OnJanuary 30, 2007, Unit 1 began coastdown (gradual reduction of reactor power due to fuel

depletion) to refueling outage 19 (RFO19). The plant was shut down on March 17, 2007, to

commence

RFO 19, which was in-progress at the end of the inspection period.Nine Mile Point Unit 2 (Unit 2) began the inspection period at 100 percent power. OnMarch 8, 2007, the 'A' reactor recirculation pump (

RRP) was secured due to seal degradation.

This caused power to be reduced to approximately 60 percent. A reactor shutdown was

commenced, and the plant reached cold shutdown on March 9, 2007. Following replacement of

the 'A' RRP seal, a reactor startup was commenced on March 14, 2007. Unit 2 achieved

100 percent power on March 18, 2007, and remained there for the rest of the inspection period.1.REACTOR

SAFETY "Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1R01Adverse Weather Protection ([[Inspection procedure" contains a listed "[" character as part of the property label and has therefore been classified as invalid. - 2 samples) a.Inspection ScopeThe inspectors completed the following two adverse weather protection samples thisinspection period. *On January 31, 2007, the inspectors reviewed]]

NMPNS's actions regarding thehigh potential for frazil ice intrusion into the Unit 1 intake structure. The

inspectors verified that operators implemented actions and monitoring specified

by the circulating water system operating procedure (OP). The inspectors also

verified that appropriate procedures were in place for loss of intake water level.

Documents reviewed for this inspection are listed in the Attachment.*On February 14, 2007, the inspectors reviewed roof loading design bases forstation structures that are important to safety due to the accumulation of recent

near-record snowfalls. The inspectors verified by discussion with

NMP [[]]

NS that

measurements of accumulated roof snow were being taken to confirm that actual

loading was within design limits. Documents reviewed included the Updated

Final Safety Analysis Reports (UFSARs) and Individual Plant Evaluations forExternal Events (IPEEE). b.FindingsNo findings of significance were identified.

2Enclosure1R04Equipment Alignment (71111.04 - 4 samples, 71111.04S - 1 sample).1Partial System Walkdown a.Inspection Scope The inspectors performed four partial system walkdowns to verify a train was properlyrestored to service following maintenance or to evaluate the operability of one train while

the opposite train was inoperable or out of service for maintenance and testing. The

inspectors compared system lineups to system OPs, system drawings, and the

applicable chapters in the

UFS [[]]

AR. The inspectors also verified the operability of critical

system components by observing component material condition during the system

walkdown and reviewing the maintenance history for each component. Documents

reviewed during this inspection are listed in the Attachment. The inspectors performed

partial walkdowns of the following systems:*Unit 2 'B'

RHR subsystem due to the 'A'

RHR subsystem being inoperable forplanned maintenance on January 17, 2007;*Unit 1 primary containment vacuum relief system during planned maintenanceon torus-to-drywell vacuum relief valve 68-02 on January 22, 2007;*Unit 2 Division 1 and 2 125 Vdc electrical systems due to safety significance onMarch 14, 2007; and*Unit 2 Division 3 emergency diesel generator (EDG) following completion ofplanned maintenance on January 27, 2007. b.FindingsNo findings of significance were identified..2Complete System Walkdown a.Inspection Scope The inspectors performed a complete walkdown of accessible portions of the Unit 1 corespray system to identify any discrepancies between the existing equipment lineup and

the specified lineup. During the walkdown, system drawings and OPs were used to

verify proper equipment alignment and operational status. The inspectors reviewed the

open maintenance work orders (WOs) on the system for any deficiencies that could

affect the ability of the system to perform its function. Documentation associated with

unresolved design issues such as temporary modifications, operator workarounds, and

items tracked by plant engineering were also reviewed to assess their collective impact

on system operation. In addition, the inspectors reviewed the CR database to verify that

equipment alignment problems were being identified and appropriately resolved.

Documents reviewed for this inspection are listed in the Attachment.

3Enclosure b.FindingsNo findings of significance were identified.1R05Fire Protection (71111.05Q - 13 samples) a.Inspection ScopeThe inspectors completed 13 quarterly fire protection inspection samples. Theinspectors toured 13 areas important to reactor safety at the station to evaluate

NMP [[]]

NS's control of transient combustibles and ignition sources and the material

condition, operational status, and operational lineup of fire protection systems includingdetection, suppression and fire barriers. The inspectors used procedure

GAP -

INV-02,

"Control of Material Storage Areas," the fire hazards analysis and pre-fire plans in

performing the inspection. Documents reviewed are listed in the Attachment. The

areas inspected included: *Unit 1 heater bays;*Unit 1 condenser bay;

• Unit 1 reactor building (RB) southeast corner room;

• Unit 1 RB southwest corner room;

• Unit 2 Division 1 switchgear room;

• Unit 2 Division 2 switchgear room;

• Unit 2 Normal (non-divisional) switchgear rooms

• Unit 2 heater bays;

• Unit 2 steam tunnel;

• Unit 2 south auxiliary bay 215 foot elevation;

• Unit 2 south auxiliary bay 196 foot elevation;

• Unit 2 'A'

RHR pump room,

RB 175 foot elevation; and

• Unit 2 'C'

RHR pump room,

RB 175 foot elevation. b.FindingsNo findings of significance were identified.1R08Inservice Inspection Activities (71111.08 - 9 samples) a.Inspection ScopeThe purpose of this inspection was to assess the effectiveness of

NMPNS 's inserviceinspection (

ISI) program for monitoring degradation of the reactor coolant system (RCS)

boundary, risk significant piping system boundaries, and the containment boundary.

The inspectors assessed the ISI activities using the criteria specified in the American

Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI

and applicable NRC regulatory requirements. Documents reviewed for this inspection

are listed in the Attachment.

4EnclosureThe inspectors selected a sample of nondestructive examination (NDE) activities forobservation and evaluation for compliance with the requirements of

ASME Section

XI.

The inspectors also selected samples of activities associated with the repair of safety

related pressure boundary components. The sample selection was based on the

inspection procedure objectives, risk significance and availability. Specifically, theinspectors focused on components and systems where degradation would result in a

significant increase in risk of core damage. This sample selection included the review of

nondestructive tests performed on dissimilar metal welds of piping to the reactor

pressure vessel (RPV) nozzles, butt welds of pipe to fitting and pipe to valves in the core

spray system and integral attachment welds to the containment spray system. The

inspectors reviewed the disposition of the results of the ultrasonic test (UT) of the RPV

N2D recirculation nozzle. This test identified an indication that exceeded the

acceptance criteria of

ASME Section

XI. The inspectors reviewed the analytical analysis

(NMP-29Q-301) of the indication that was performed in accordance with the

requirements of

ASME Section

XI, IWB-3600. The analysis concluded that the flaw

indication was acceptable without repair or rework for one additional refueling cycle at

which time (2009) it would be reexamined by UT.The inspectors performed an evaluation of work activities during a drywell entry thisinspection and noted the corrosion and loss of coating on the reactor building closed

loop cooling piping. The condition had been previously noted by

NMP [[]]

NS but the

inspectors requested an updated evaluation of the condition that was provided in the

disposition of CR 2007-1905. The updated ultrasonic wall thickness measurements

verified that the structural integrity and pressure retention capabilities of the piping was

maintained within specification requirements.The inspectors reviewed portions of the in-process remote visual examination (VT) ofthe steam dryer and observed portions of the replacement of component parts of the

in-vessel shroud tie rod assemblies. The inspectors reviewed a sample of CRs that

were initiated as a result of the inspections performed in accordance with

NMPNS 's

ISI

program. The inspectors reviewed the problem identification, cause analysis and

corrective actions provided in the disposition of the selected CRs. The inspectors

evaluated these activities for compliance with the requirements of the

AS [[]]

ME Code and

CFR 50, Appendix B, Criterion

XVI.The inspectors performed a direct observation of three nondestructive tests and alsoperformed a documentation review of two tests that included both volumetric and

surface examinations. The inspectors also performed a VT of selected areas of the

containment liner to assess the condition of the liner coating. As a result of the

inspectors' examination, supplemental inspection was performed to acquire additional

liner wall thickness measurements. WO 07-03718-00 was initiated to provide

instructions for surface preparation to accommodate thickness testing. Thickness

measurements were specified in action item four of the disposition to CR 2007-1695 and

recorded in

NDE report 1-6.05-07-0009. The following

NDEs were reviewed:*UT, volumetric examination, weld # 40-WD-045, butt weld, pipe to elbow, corespray system (40);

5Enclosure*UT, volumetric examination, weld # 40-WD-047, butt weld, pipe to valve, corespray system (40);*Magnetic particle test (MT), surface examination, containment spray,W-1-4.00-07-012, pipe to saddle weld #80-13-WD-001;*Liquid penetrant test (PT), surface examination, weld 33.2-6-R05-WD-001,integral attachments to reactor water clean up (RWCU) piping, data report

W-1-3.00-07-001; and*VT-1, visual surface examination of damage of the

RPV head and vessel flangeat stud #27,

NDE report 1-2.01-07-0042.The inspectors selected a sample of repair/rework activities for review that required thedevelopment and implementation of an

ASME Section

XI repair plan. The inspectors

reviewed documentation for the planned weld repair on the pressure boundary of two

ASME risk significant systems.

WO 05-12874-02 was initiated for the weld repair of the

heat exchanger stationary channel cover on Unit

2 EDG heat exchanger 2

EGS*E1C that

involved restoration of corroded locations and sealing surfaces by depositing weld metal

on an

ASME pressure boundary (safety class 1) component.

WO 07-03643-00 was

initiated for the rework of damage to the reactor head and vessel flange in the vicinity of

stud #27. The inspectors reviewed the

ASME Section

XI plans, work scope, activity

sequence, weld filler metal selection, weld procedure specifications and procedure

qualification records (PQR), welder qualifications, specified non-destructive tests,

acceptance criteria and post work testing.The inspectors selected two CRs for review in which a nondestructive examinationidentified a nonconforming condition that was accepted for continued service without

repair or rework. Components identified in

CR s 2003-1064 (

RPV head flange) and

2007-1477 (reactor building closed loop cooling pipe support) were visually inspected

and nonconforming conditions were noted that were evaluated and accepted for

continued service without repair or rework. b.FindingsNo findings of significance were identified.1R11Licensed Operator Requalification Program (71111.11Q - 2 samples) a.Inspection ScopeThe inspectors completed two licensed operator requalification training program (LORT)inspection samples. Documents reviewed for this inspection are listed in the

Attachment. For each scenario observed the inspectors assessed the clarity and

effectiveness of communications, the implementation of appropriate actions in response

to alarms, the performance of timely control board operation and manipulation, and the

oversight and direction provided by the shift manager. During the scenario the

inspectors also compared simulator performance with actual plant performance in the

control room. The following simulator scenarios were observed:

6Enclosure*On February 9, 2007, the inspectors observed Unit

1 LO [[]]

RT to assess operatorand instructor performance during a scenario involving a feedwater pump trip,

turbine vibrations, and a steam leak in containment that required initiation of

containment spray. The inspectors evaluated the performance of risk significant

operator actions including the use of emergency operating procedures (EOPs,)

N1-EOP-2, "RPV Control," and N1-EOP-4, "Primary Containment Control."*On March 2, 2007, the inspectors observed Unit

2 LO [[]]

RT to assess operator andinstructor performance during a scenario that involved a steam leak in the

drywell followed by a reactor scram in which several control rods failed to insert.

The inspectors evaluated the performance of risk significant operator actions

including the use of

EOP s, N1-

EOP-C5, "Failure to Scram," and N2-EOP-PC,

"Primary Containment Control." b.FindingsNo findings of significance were identified.1R12Maintenance Effectiveness (71111.12Q - 2 samples) a.Inspection ScopeThe inspectors completed two maintenance effectiveness inspection samples. Theinspectors reviewed performance-based problems involving selected in-scope

structures, systems, or components (SSCs) to assess the effectiveness of the

maintenance program. Reviews focused on: proper Maintenance Rule (MR) scoping in

accordance with 10 CFR 50.65; characterization of reliability issues; changing system

and component unavailability; 10 CFR 50.65 (a)(1) and (a)(2) classifications; identifying

and addressing common cause failures, trending key parameters, and the

appropriateness of performance criteria for SSCs classified (a)(2) as well as the

adequacy of goals and corrective actions for SSCs classified (a)(1). The inspectors

reviewed system health reports, maintenance backlogs, and MR basis documents.

Other documents reviewed for the inspection are listed in the Attachment. The following

two

MR samples were reviewed:*Unit 1 emergency cooling (

EC) system performance; and*Unit 2 EDG ventilation system motor operated damper failures. b.FindingsNo findings of significance were identified.

7Enclosure1R13Maintenance Risk Assessments and Emergent Work Control (71111.13 - 8 samples) a.Inspection Scope The inspectors reviewed risk assessments for the following eight work weeks during theinspection period. The inspectors verified that risk assessments were performed in

accordance with

GAP -

OPS-117, "Integrated Risk Management," that risk of scheduled

work was managed through the use of compensatory actions and schedule adherence;

and that applicable contingency plans were properly identified in the integrated work

schedule. Documents reviewed for the inspection are listed in the Attachment. The following workweeks were reviewed:Unit 1*Week of January 22, 2007, that included a two-day rebuild of the actuator fortorus-to-drywell vacuum relief valve 68-02, a containment spray loop 112

quarterly surveillance, and a two-day period for annual maintenance on the

diesel fire pump.*Week of January 29, 2007, that included emergent troubleshooting on the maingenerator amplidyne brushes, 115 kilovolt (kV) switchyard relay testing, below

freezing outside air and lake temperatures, and standby liquid control system

and emergency service water system surveillance testing.*Week of February 26, 2007, that included testing and emergent troubleshootingon the

EDG 102 cool down circuit, extent of condition

EDG 103 surveillance

testing, planned maintenance on Line 8 345 kV switchyard breakers, and core

spray 111 and 121 surveillance testing.*Week of March 5, 2007, that included planned maintenance on Line 8 345 kVswitchyard breakers, a standby liquid poison system monthly surveillance, and

EDG raw water system performance testing to evaluate flow degradation.Unit 2*Week of January 15, 2007, that included planned maintenance and testing on 'A'

RHR system, 345 kV switchyard protective relay testing, and low pressure core

spray and Division

1 EDG testing. *Week of January 22, 2007, that included planned maintenance on the highpressure core spray system, the Division 3

EDG, and the 'F' service water pump

and strainer. *Week of February 12, 2007, that included planned maintenance and testing onthe Division

1 EDG , 345 kV switchyard relay testing, and 'A'

RHR system testing.*Week of March 5, 2007, that included a Division 2 EDG monthly surveillance,Division 2 loss of offsite power / loss of coolant accident quarterly relay testing,

and a standby liquid control system quarterly surveillance. b.Findings

8EnclosureNo findings of significance were identified.1R15Operability Evaluations (71111.15 - 8 samples) a.Inspection Scope The inspectors reviewed operability determinations associated with the eight CRs listedbelow. The inspectors evaluated the acceptability of the selected determinations; when

needed, the use and control of compensatory measures; and the compliance with TSs.

The inspectors' review verified that the operability determinations were made as

specified by procedure

CNG -

NL-1.01-1003, "Conduct of Operability Determinations."

The technical adequacy of the determinations was reviewed and compared to the

TS s,

UFS [[]]

AR, Technical Requirements Manual and associated design basis documents

(DBD.) Other documents reviewed for this inspection are listed in the Attachment. The

following eight evaluations were reviewed:*CR-2006-5855 concerning the hinge pin cover leak on feedwater supply checkvalve

2FWS *23B; *

CR -2007-0300 concerning the automatic scram that occurred at MonticelloNuclear Station after all four turbine control valves opened unexpectedly;*CR-2007-0448 concerning the spiking on local power range monitor,

LPRM 28-25C, that inputs to average power range monitor,

APRM 14;*CR 2007-0181 and 2007-0211 concerning an intermittent closed positionindicating light for Unit 1 electromatic relief valve,

ERV -113;*

CR 2007-0870 concerning a 10 CFR 50 Part 21 notification on non-conservativeassumptions in the design analysis of the Unit 2 emergency core cooling system

strainer crush pressure;*CR 2007-0838 concerning

EC system temperature changes that resulted fromremoval of

EC system insulation in preparation for the refueling outage;*CR 2007-0869 concerning requirements for maintaining the automatic isolationfunction of the shutdown cooling system isolation valves during cold shutdown

and refueling; and*CR 2007-1090, concerning continued operation with packing leakage from theRCIC system steam supply outboard containment isolation valve,

2ICS *

MOV121. b.FindingsNo findings of significance were identified.

9Enclosure1R19Post Maintenance Testing (71111.19 - 8 samples) a.Inspection ScopeThe inspectors completed eight post maintenance testing inspection samples. Theinspectors reviewed post maintenance test procedures and associated testing activities

for selected risk significant Mitigating Systems to assess whether the effect of

maintenance on plant systems was adequately addressed by control room and

engineering personnel. The inspectors verified that test acceptance criteria were clear;

demonstrated operational readiness and were consistent with DBDs; that test

instrumentation had current calibrations and the range and accuracy for the application;

and that tests were performed, as written, with applicable prerequisites satisfied. Upon

completion, the inspectors verified that equipment was returned to the proper alignment

necessary to perform its safety function. The adequacy of the identified post

maintenance testing requirements were verified through comparisons with the

recommendations of

GAP -

SAT-02, "Pre/Post-Maintenance Test Requirements," and the

design basis documentation contained in the

TS s,

UFSAR and associated design basis

documentation. Other documents reviewed for this inspection are listed in the

attachment. The following post-maintenance test activities were reviewed:*Unit 1,

WO 06-03769-00 that disassembled and rebuilt the actuator for

BV68-02. The retest was performed in accordance with N1-ST-SA6, "Drywell/Torus and

Torus/RB Vacuum Reliefs Test," and N1-ST-R11, "Valve Remote Position

Indicator Verification." *Unit 1,

WO 05-22434-00 and

WO-06-20636-00 that performed annualpreventative maintenance and engine speed adjustments for the diesel fire

pump. The retest was performed in accordance with N1-PM-W9, "Fire

Protection System - Weekly Operation of Fire Pumps." *Unit 2,

WO 06-22403-02 that repaired a steam leak on the hinge pin cover forfeedwater to

RPV isolation check valve 2FWS*23B. The retest was performed in

accordance with N2-ISP-LRT-R@102, "Type "C" Containment Isolation Valve

Vacuum Leak Rate Test

2FWS *V12A, 2

FWS *V12B, 2FWS*V23A,

2FWS *V23B."*Unit 2,

WO 06-11287-00 that replaced logic unit C33-K638B-1 for the B feedwater pump level control valve,

2FWS -

LV-10B. The retest was performed in

accordance with the

WO step text and S-

EPM-GEN-063, "Limitorque

MOV Testing."*Unit 2,

WO 07-01313-00 that replaced reactor protection system relayC72A-K14L. The retest was performed in accordance with N2-

ISP-RPS-R211,

"Channel Scram Response Time Test," and N2-OSP-RPS-W002, "Manual

Scram Channel Functional Test."*Unit 2,

WO s 05-02332-00 and 05-01272-00 that performed maintenance onservice water pump 'F' discharge strainer, 2

SWP*STR4F, and discharge check

valve, 2SWP*V1F. The retest was performed in accordance with

N2-OSP-SWP-Q002, "Service Water Pump and Valve Operability Test," and

N2-OSP-SWP-Q004, "Division 2 Service Water Operability Test."

10Enclosure*Unit 2,

ACR 06-5782 that tightened the valve packing of the 'C'

RHR systemminimum flow valve,

2RHS *

MOV4C. The retest was performed in accordance

with N2-OSP-RHS-Q003, "RHR System Loop C Valve Operability Test." *Unit 2,

WO 05-20370-00 that performed preventative maintenance on theDivision 3

EDG and auxiliary equipment. The retest was performed in

accordance with N2-OSP-EGS-M@002, "Diesel Generator and Diesel Air Start

Valve Operability Test - Division III." b.FindingsNo findings of significance were identified.1R20Refueling and Other Outage Activities (71111.20 - 1 sample) a.Inspection Scope Forced Outage 2F701: The inspectors observed and reviewed the following activitiesduring the Unit 2 forced outage F701 from March 8 to March 16, 2007. Documents

reviewed for this inspection are listed in the Attachment.*The inspectors observed portions of the plant shutdown and cooldown andverified that the

TS cooldown rate limits were satisfied.*The inspectors reviewed outage schedules and procedures and verified that

TSrequired safety system availability was maintained, shutdown risk was

considered, and that contingency plans existed to restore key safety functions

such as electrical power and containment integrity.*The inspectors performed a walkdown of the drywell to identify evidence of RCSleakage, and verify the condition of drywell coatings, structures, valves, piping,

supports and other equipment. The inspectors also verified that no debris was

left in the drywell that could affect the performance of the emergency core

cooling system suction strainers.*The inspectors observed portions of the reactor startup following the outage, andverified through plant walkdowns, control room observations, and surveillance

tests (ST) reviews that safety-related equipment required for mode change was

operable.Refueling Outage 1RFO19: The inspectors observed and/or reviewed the following Unit1 refueling outage activities to verify that operability requirements were met and that

risk, industry experience, and previous site specific problems were considered. The

refueling outage and inspection sample were in-progress at the end of the inspection

period. Documents reviewed for this inspection are listed in the Attachment.*The inspectors reviewed outage schedules and procedures, and verified thatTS-required safety system availability was maintained and shutdown risk was

minimized. The inspectors verified that when specified by

NUMA [[]]

RC 91-06,

"Guidelines for Industry Actions to Assess Shutdown Management," and

NMP [[]]

NS 11Enclosureprocedure

NIP -

OUT -01, "Shutdown Safety," contingency plans existed forrestoring key safety functions. *The inspectors observed portions of the plant shutdown and cooldown onMarch 17 and verified that the

TS cooldown rate limits were satisfied.*Through plant tours, the inspectors verified that

NMPNS maintained andadequately protected electrical power supplies to safety-related equipment and

that TS requirements were met.*The inspectors verified proper alignment and operation of shutdown cooling andother decay heat removal systems. The verification also included reactor cavity

and fuel pool makeup paths and water sources and administrative control of

drain down paths.*The inspectors reviewed N1-FHP-25, "General Description of Fuel Moves,"N1-FHP-27C, "Core Shuffle," N1-ODP-NFM-101, "Refueling Operations," and

TS, and verified all requirements for refueling operations were met through refuel

bridge observations, control room panel walkdowns and surveillance procedure

reviews.*After the drywell was opened for general access, the inspectors performed an"as-found" walkdown to identify evidence of RCS leakage and verify the

condition of drywell structures, piping, and supports. b.FindingsNo findings of significance were identified.1R22Surveillance Testing (71111.22 - 8 samples) a.Inspection ScopeThe inspectors completed eight quarterly surveillance testing inspection samples. Theinspectors witnessed performance of and/or reviewed test data for eight risk-significant

ST s to assess whether the

SSC s tested satisfied

TS ,

UFSAR, Technical Requirements

Manual, and

NMP [[]]

NS procedure requirements. The inspectors verified that test

acceptance criteria were clear, demonstrated operational readiness and were consistent

with the DBDs; that test instrumentation had current calibrations and the range and

accuracy for the application; and that tests were performed, as written, with applicable

prerequisites satisfied. Upon ST completion, the inspectors verified that equipment was

returned to the status specified to perform its safety function. Documents reviewed for

this inspection are listed in the Attachment. The following eight

ST s were reviewed:*N2-

ISP -LDS-Q007, "Quarterly Functional Test of

RHR Equipment Area andGeneral

RB Area Temperature Instrument Channels

2RHS *

TE 49A,

2RHS *

TE 49B,

2RHS *

TE 49C, and

2RHS *

TE49D;"*N1-ST-Q6C, "Containment Spray System Loop 112 Quarterly Operability Test;"

• N2-OSP-RHS-Q@006, "RHR System Loop C Pump and Valve Operability Testand System Integrated Test;"*N1-ST-Q1B, "Core Spray 121 Pump, Valve and Shutdown Cooling Water SealCheck Valve Operability Test;"

2Enclosure*N1-ST-R9, "Core Spray Operability Test Using Demineralized Water;" *N1-ST-M4A, "EDG 102 and PB 102 Operability Test;"

• N2-OSP-CSH-Q@002, "High Pressure Core Spray Pump and Valve Operabilityand System Integrity Test;" and*N2-OSP-EGS-M@002, "Diesel Generator and Diesel Air Start Valve OperabilityTest - Division

III. " b.Findings Introduction. A self-revealing Green

NCV of

TS 5.4, "Procedures," was identified onJanuary 11, 2007, when the Unit 2

RCIC system automatically isolated as a result of an

improperly performed surveillance procedure. When performing a test of the

temperature instrument that provides

RHR and

RCIC system high area temperature

isolations, technicians failed to ensure that the affected channel was bypassed prior to

disconnecting the input thermocouple. This resulted in an automatic isolation of the

RCIC system steam supply.Description. On January 11, 2007, instrument and controls technicians were performinga quarterly

ST of the high area temperature automatic isolation for the

RCIC and

RHR

systems. This function was provided by four channels of the reactor building (RB)

ambient temperature instrumentation. The test was performed using a test device in

place of the instrument channel input thermocouple to verify the high temperature

isolation setpoint. To prevent inadvertent actuation prior to disconnecting the input

thermocouple to install the test device, the associated system automatic isolation

function must be bypassed. This was done using a keylocked

RHR /

RCIC isolation

bypass switch.The surveillance procedure, N2-ISP-LDS-Q007, "Quarterly Functional Test of

RHRE quipment Area and General

RB Area Temperature Instrument Channels

2RHS *

TE 49A,

2RHS *

TE 49B,

2RHS *

TE 49C, and

2RHS *

TE49D," contained separateand similar attachments for each of the four temperature instrument channels. After

successfully completing the first two attachments, the technicians went on to test the

third temperature channel. However, in this case, the lead technician signed the

procedure to indicate that the

RHR /

RCIC isolation switch had been placed in "bypass"

before it was actually completed. The lead technician then directed the technician to

disconnect the thermocouple. Because the

RHR /

RCIC isolation switch was not in the

"bypass" position, this caused an automatic isolation of the

RC [[]]

IC steam supply.

Operators immediately recognized the error and halted the surveillance procedure.

Technicians reconnected the thermocouple, and operators restored

RC [[]]

IC to a normal

standby lineup. During the four hours that the

RC [[]]

IC steam supply was isolated, the

RCIC system was inoperable and unavailable. The

TS allowed outage time for the

RCIC system is 14 days.Analysis. The performance deficiency associated with this event was that techniciansdid not properly follow a surveillance test procedure, which caused the Unit 2

RCIC

system to automatically isolate, rendering the system unavailable to perform its safety

function. The procedure directed operators to place the

RHR /

RCIC isolation bypass

13Enclosureswitch in the "bypass" position and to verify that the switch was in "bypass" by twoindependent means prior to disconnecting the thermocouple. The technician did not

perform these steps but marked them completed. The finding is greater than minor

because it was associated with the human performance attribute of the Mitigating

Systems cornerstone and adversely affected the cornerstone objective to ensure the

availability, reliability, and capability of systems that respond to Initiating Events to

prevent undesirable consequences. The finding was determined to be of very low

safety significance in accordance with IMC 0609, Appendix A, "Determining the

Significance of Reactor Inspection Findings for At-Power Situations." The inspectors

evaluated the significance of this finding using IMC 0609, Appendix A, Phase 1, and

determined that a Phase 2 analysis was required because the finding represented an

actual loss of the

RCIC system safety function for four hours. The Region I

SRA

determined that a Phase 3 analysis was necessary because the site-specific Phase 2

notebook indicated that the finding could be more than of very low safety significance

assuming an exposure time of three days. The

SRA used the Nine Mile Point Unit 2

SP [[]]

AR model and the actual four-hour exposure time to determine that the increase in

core damage frequency was in the range of 1 core damage accident in 125,000,000

years of reactor operation, high E-9 per year. The

SP [[]]

AR model dominant cutsets were

a station blackout with failure of high pressure injection sources and the inability to

restore

AC power within 30 minutes. Based on this review, the

SRA concluded that the

finding was of very low safety significance. This finding has a cross-cutting aspect in

the area of human performance because the technicians failed to use appropriate

human error prevention techniques, such as self-checking and prominent visual

identification of critical procedure steps.Enforcement. TS 5.4, "Procedures," states, in part, that, written procedures shall beestablished, implemented, and maintained covering the applicable procedures

recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, Item 8, "Procedures for

Control of Measuring and Test Equipment and for STs, Procedures, and Calibrations,"

lists containment isolation tests as an applicable group of tests. Contrary to the above,

Unit 2 Instrument Surveillance Procedure N2-ISP-LDS-Q007, "Quarterly Functional Test

of

RHR Equipment Area and General

RB Area Temperature Instrument Channels

2RHS *

TE 49A,

2RHS *

TE 49B,

2RHS *

TE 49C, and

2RHS *

TE49D," was not correctlyimplemented. On January 11, 2007, Procedure Attachment 3 step 7.2.1, place and

verify the

RHR /

RCIC isolation channel bypass switch in the "bypass" position, was not

completed prior to performing Attachment 3 step 7.2.2, to disconnect the associated

channel thermocouple leads. Procedure step 5.2 in Section 5.0 "Limitations and

Actions," states, "Steps in Section 7.0 and 8.0 shall be performed in sequence."

Because this procedural noncompliance is of very low safety significance and was

entered into the

CAP as

CR 2007-0186, this violation is being treated as an

NCV ,consistent with Section

VI.A of the

NRC Enforcement Policy:

NCV 05000410/2007002-01, Failure to Follow Procedure Caused Inadvertent Isolation of

RC [[]]

IC Steam Supply.1R23Temporary Plant Modifications (71111.23 - 2 samples)

14Enclosure a.Inspection ScopeThe inspectors completed two temporary modification inspection samples. For thetemporary change packages (TCPs) listed below the inspectors verified that the

installation and/or removal of temporary modifications did not affect the safety functions

for the associated systems. The inspectors assessed the adequacy of the 10 CFR 50.59

evaluations; verified that the changes did not adversely affect the system's ability to

perform its design functions as described in the

UFSAR and

TS; that the installation and

removal was consistent with the modification documentation; that the drawings and

procedures were updated as applicable; and that the post-installation and restoration

testing was adequate.*TCP No. N2-06-091, Leak Seal for

2FWS *23B, Revision 1*

TCP No. N2-06-091, Leak Seal for

2FWS *23B, Revision 2 b.FindingsNo findings of significance were identified. Cornerstone: Emergency Preparedness1

EP6Drill Evaluation (71114.06 - 1 sample) a.Inspection Scope The inspectors completed one drill evaluation inspection sample. The inspectorsobserved simulator, technical support center and emergency operations facility activities

associated with the Unit 1 emergency planning drill on March 1, 2007. The inspectors

verified that emergency classification declarations and notifications were completed in

accordance with

10 CFR 50.72, 10

CFR 50, Appendix E, and the Nine Mile Point

emergency plan implementing procedures. Documents reviewed for this inspection are

listed in the Attachment. b.FindingsNo findings of significance were identified.

15Enclosure4.OTHER

ACTIVI [[]]

TIES4OA2Identification and Resolution of Problems.1Review of Items Entered into the CAP a.Inspection ScopeAs specified by Inspection Procedure 71152, "Identification and Resolution ofProblems," and in order to help identify repetitive equipment failures or specific human

performance issues for follow-up, the inspectors performed a daily screening of all items

entered into

NMPNS 's

CAP. The review was accomplished by accessing the

computerized database for

CR s and attending

CR screening meetings. In accordance

with the baseline inspection modules the inspectors also selected 73 CAP items across

the Initiating Events, Mitigating Systems, Barrier Integrity, and Public Radiation Safety

cornerstones for additional follow-up and review. The inspectors assessed

NMP [[]]

NS's

threshold for problem identification, the adequacy of the cause analyses, extent of

condition review, operability determinations, and the timeliness of the specified

corrective actions. The

CR s reviewed are listed in the Attachment. b.FindingsNo findings of significance were identified.4

OA 3Event Followup (71153 - 2 samples).1Loss of Unit 1 Plant Vent Effluent Normal Monitoring CapabilityOn January 26, the Unit 1 off-gas effluent stack monitoring system (OGESMS) wasdeclared inoperable due to low sample flow. With

OGES [[]]

MS inoperable, the Offsite

Dose Calculation Manual (ODCM) required that auxiliary sampling be placed in service

within eight hours. However, due to the low sample flow, attempts to place the auxiliary

stack gas sampling system in service were unsuccessful. As a result, Unit 1 could not

satisfy the

OD [[]]

CM stack sampling requirements for noble gas, particulate, and iodine.

The

OD [[]]

CM did not specify actions if both the normal and auxiliary sampling systems

were unavailable. Therefore, in response to the event,

NMP [[]]

NS developed an alternate

monitoring procedure to use in-plant monitoring equipment to estimate stack effluent

release rates.This event occurred during a period of severe winter weather.

NMP [[]]

NS suspected thecause to be an ice blockage in the common sample line. Because the sample point is

near the top of the plant stack, the weather conditions did not support direct

investigation.

NMP [[]]

NS attempted to clear the obstruction using heated pressurized

nitrogen. On January 27, 2007, this method was successful, and

OGES [[]]

MS was

returned to service. However, the sample line again became obstructed on

February 3, 2007, forcing Unit 1 to revert to the alternate monitoring procedure for stack

effluent monitoring. On February 20, 2007, weather conditions moderated to the point

16Enclosurethat the pressurized nitrogen method successfully cleared the sample line and workersreplaced the heat trace and line insulation on the exposed portion of sample line at the

top of the stack.The inspectors reviewed

NMPNS 's response to the loss of

OGESMS and reviewed thealternate monitoring procedure. The inspectors examined the event in terms of its effect

on

NMP [[]]

NS's ability to implement their emergency plan, as well as its effects on public

radiation safety. b.FindingsNo findings of significance were identified. .2'A' Reactor Recirculation Pump Seal Degradation (Event Notification 43223)During restoration from a planned power reduction on February 3, 2007, short durationperturbations were observed in normally stable pressures and temperatures associated

with the 'A'

RRP seal assembly. After several hours, indications returned to normal.

NMP [[]]

NS suspected that the perturbations were caused by foreign material flushed

through the seal. Operations issued a special order to establish additional monitoring of

seal parameters while changing plant conditions.Infrequent short duration seal parameter perturbations occurred randomly over the nextseveral weeks. On March 8, 2007, a sudden, substantial increase in upper seal cavity

pressure occurred, indicating that the inboard seal had failed. Operators secured and

isolated the 'A'

RRP in accordance with the

OP for RRP seal failure. This caused a

power reduction to approximately 60 percent. After stabilizing and assessing plant

conditions, operators proceeded to shut down the plant to repair the 'A'

RRP seal.The inspectors reviewed

NMPNS 's response to the short term seal parameterperturbations, and observed the operators' response to the 'A'

RRP seal degradation. b.FindingsNo findings of significance were identified.4

OA 5Other Activities.1(Closed)

URI 05000220/2006008-03

PRA Assumptions Regarding

SBO Coping Time a.Inspection ScopeThis unresolved item was opened to complete a review of the impact of an incorrectprobabilistic risk assessment (

PRA) assumption that there was a high probability that

certain 11 station battery loads would be de-energized (shed) within 15 minutes of the

start of a station blackout (SBO) event. The inspectors considered this assumption

incorrect because the SBO procedure did not direct load shedding until 30 minutes into

17Enclosurethe event, the SBO procedure required other time consuming steps before loadshedding, and the operators would not have secured the loads prematurely because

some loads provided useful indications and alarms. The inspectors reviewed

NMPNS 's report

SAS-04-06, "PRA Margin Assessment for Unit1 Station Blackout DC Load Shedding." Specifically, the inspectors verified that load

shedding times coincided with SBO procedure requirements; that average, realistic

values were used for input assumptions; and that the probability of failing to load shed

was dependent on the failure to meet the procedural load-shedding times.Based on the review of

SAS -04-06 and interviews with electrical design and

PRAengineers, the inspectors determined that although the stated time in the PRA for load

shedding during an SBO was incorrect, satisfactory margin remained for 11 station

battery capacity if SBO procedure load shed time requirements were met. No violations

of NRC requirements were identified. This item is closed. b.FindingsNo findings of significance were identified..2Review of the Institute of Nuclear Power Operations 2006 Evaluation a.Inspection ScopeThe inspectors reviewed the interim report of the Institute Nuclear Power OperationsNovember 2006 evaluation of Nine Mile Point dated January 2, 2007. The inspectors

reviewed the report to ensure that issues identified were consistent with the

NRC perspective of

NMP [[]]

NS's performance and to identify significant safety issues that

required

NRC follow-up. b.FindingsNo findings of significance were identified.4

OA 6Meetings, Including ExitExit Meeting SummaryThe inspectors presented the inspection results to Mr. Mark Schimmel and othermembers of

NMPNS 's management on April 20, 2007.

NMPNS acknowledged that

some of the material reviewed by the inspectors during this period was proprietary, but

that the content of this report includes no proprietary information.ATTACHMENT:

SUPPLE [[]]

MENTAL [[]]

INFORM [[]]

ATION A-1AttachmentSUPPLEMENTAL

INFORM [[]]

ATIONK EY

POINTS [[]]

OF [[]]

CONTAC [[]]

TLicensee personnelN. Conicella, Manager, OperationsR. Dean, Director, Quality and Performance Assessment

M. Faivus, General Supervisor, Chemistry

J. Gerber, General Supervisor, Radiation Protection

J. Laughlin, Manager, Engineering Services

T. Maund, Manager, Maintenance

M. Miller, Director, Licensing

K. Nietmann, Site Vice President

W. Paulhardt, Manager, Integrated Work Management

M. Schimmel, Plant General Manager

T. Shortell, Manager, Training and Performance Improvement, Nuclear

LIST [[]]

OF [[]]

ITEMS [[]]

OPENED ,

CLOSED ,

AND [[]]

DISCUS SEDOpened and Closed05000410/2007002-01NCVFailure to Follow Procedure CausedInadvertent Isolation of

RC [[]]

IC Steam Supply

(Section 1R22)Closed05000220/2006008-03URIPRA Assumptions Regarding

SBO CopingTime (Section 4

OA 5)LIST

OF [[]]

DOCUME NTS

REVIEW [[]]

EDS ection 1R01: Adverse Weather ProtectionUnit 1 and

2 UFSAR sUnit 1 and 2

IPEEEs

CR 2004-0385, Sudden Unit 1 intake structure icing while on reverse flow

N1-OP-19, "Circulating Water System"

N1-SOP-19, "Intake Structure Icing"

N1-SOP-18.1, "Service Water Failure, Low Intake Level"

O1-OPS-001-275-1-01, "Circulating Water System"

O3-OPS-009-JIT-3-01, "Just-in-time training for Plant Startup"

O3-OPS-009-JIT-3-02, "Just-in-time training for Plant Shutdown"

A-2AttachmentCR 2006-4584, Known deficiencies not corrected on equipment important for summerreadiness at Unit 2

Steven F. Daly, Cold Regions Technical Digest No. 91-1, "Frazil Ice Blockages of Intake Trash

Racks," March 1991

NAI -

TQS-20, "Operator Continuing Training Biennial and Cyclic Schedule Development andMaintenance"

N1-275000-RBO-13, "Events and Human Performance"Section 1R04: Equipment AlignmentUnit

1 UFSARU nit 2

UFSAR

N1-OP-2, "Core Spray System"

N2-OP-31, "RHR System"

N2-VLU-01, "Walkdown Order Valve Lineup and Valve Operations," Attachment 31, "N2-OP-31

Walkdown Valve Lineup"

N2-OP-74A, "Emergency DC Distribution"

N2-OP-71D, "Uninterruptible Power Supplies (UPS)"

PI&R C-18006-C

PI&R C-18007-C

N2-OP-100B, "HPCS Diesel Generator"Section 1R05: Fire ProtectionNine Mile Point Unit

1 UFSAR , Appendix 10

AN ine Mile Point Unit

2 UFS [[]]

AR , Appendix 9A

GAP -

INV-02, Revision 17, Control of Material Storage Areas

N1-FPI-PFP-0101, "Pre-fire Plans," Revision 1

N2-FPI-PFP-0201, "Pre-fire Plans," Revision 0Section 1R08: Inservice Inspection ActivitiesExamination ProceduresNDEP-UT-6.28 R00Ultrasonic Examination of Dissimilar Metal Piping Welds (Manual)PDI-UT-10 Revision A,

PDI Generic Procedure for the

UT examination of dissimilar metal piping

welds

NDEP -

PT -3.00 R16Liquid Penetrant Examination

NDEP -

MT -4.00 R15Magnetic Particle Examination

NDEP -

VT -2.01 R18VT

ASME [[]]

XIExamination ReportsW-1-2.01-07-001VT-3 Examination Data of support 70-R19-B, broken bolt headW-1-4.00-07-001Magnetic Particle Examination Data, integral attachments, pipe support,system 93, Containment SprayW-1-3.00-07-001Liquid Penetrant Examination Data, integral attachments, system 33,RWCUW-1.2.01-07-0042VT-1 Examination Report, RPV head flange, slight corrosion deterioration

A-3AttachmentW-1-4.00-07-012Magnetic Particle Examination Data, pipe to saddle weld # 80-13WD001,Reactor Containment SprayW-1-6.24-07-105UT report, Weld # 40-WD-045, butt weld, core spray system

W-1-6.24-07-107UT report, Weld # 40-WD-047, butt weld, pipe to valve, core spraysystemNDE 1-6.05-07-0009UT report, drywell liner thickness data in the vicinity of area coolers #11,15(two locations) and 16. Work Orders07-03643-00RPV flange, repair damage at stud location #27 (vessel flange)

06-18382-00Removal and Installation of Recirculating Pump Seals, 2RCS P1A

05-12874-02Repair of Corroded areas of Channel Cover (2EGS E1C 000)

07-03718-00Ultrasonic Examination Report of wall thickness readings of corrosion onthe drywell linerWelding ProceduresS-MAP-SPC-0102 Welding/Brazing Procedure Specifications (Revision 27)WPS-8-8-BA-102Manual gas tungsten arc welding (GTAW) and shielded metal arc(SMAW) welding of P8 to P8WPS-1-1-BA-101Manual

GTAW and

SMAW of P1 to P1

WPS -8-8-

BA -102Manual

GTAW and

SMAW of P8 to P8

PQR N107Manual

GTAW and

SMAW [[]]

PQR [[]]

PQR N203Shielded Metal Arc Welding

PQR [[]]

PQR N120Manual

GTAW and

SMAW [[]]

PQR (P1 to P1)

PQR N177Manual

GTAW and

SMAW [[]]

PQR (P1 to P1)MiscellaneousNMP1-EDM-Traveler-001Traveler for

NMP 1-

EDM -001 at 90/270 and 350 degree positionsNMP1-EDM-001 R0Nine Mile Point 1 Shroud Repair Project

NMP 1-

STR -Traveler-001Traveler for

NMP 1-

INSTALL-001 at 90/270 and 350 degreepositionsCN 006503Change Notice - evaluation of core flow/core power effects

NIR 19 2007Tie Rod Inspection Checklist

DCP N1-06-090 R00Design Change Procedure - Modify Core Shroud Tie Rod UpperSupport AssembliesAppendix

BA ging Management Programs and Activities

NER -

IS -033 R1Evaluation of

RBCLC Piping Inside Drywell During

RFO 17

NMPNS -

SBI -001 R1Small Bore Piping Corrosion Monitoring Program

DRF 0000-0057-1468Shroud Repair Inspection Recommendations-

NMP 1

DER 1-93-0339External Corrosion Noted on

RBCLC system components

DrawingsE231-563-0Vessel Forming and Welding - Upper

E231-577-0RPV Miscellaneous Details - Head to Vessel O-Rings

E231-575-3RPV Closure Head Final Machining

F-45183-C R4RWCU, weld 33.2-6-R-05-WD-001

R19-B R2RB Closed Loop Cooling, Support 70-R19-B

CalculationsS13.4-70-M003System 70,

RBC [[]]

LC, Minimum Wall Thickness (1986)

S13.4-70-TP15System 70,

RBC [[]]

LC, Minimum Wall Thickness (1995)

A-4AttachmentSection 1R11: Licensed Operator RequalificationNMPNS Operations ManualNEI 99-02, "Regulatory Assessment Performance Indicator Guidelines," Revision 4

CNG -

HU -1.01, "Human Performance Program"

CNG -

HU -1.01-1000, "Human Performance"

CNG -

HU-1.01-1001, "Human Performance Tools and Verification Practices"

S-ODP-OPS-0001, "Conduct of Operations"

N1-SOP-1, "Reactor Scram"

N2-SOP-101C, "Reactor Scram"

N1-EOP-02, "RPV Control"

N1-EOP-05, "Secondary Containment Control"

N2-ARP-01, "Control Room Alarm Response Procedures."

N2-EOP-RPV, "RPV Control"

Unit 1 Alarm response procedures

N1-SOP-31.1, "Turbine Trip"

N1-SOP-16.1, "Feedwater System Failures"

N1-SOP-1.1, "Emergency Power Reduction"

EPIP -

EPP -01, "Classification of Emergency Conditions at Unit 1"

EPIP -

EPP -02, "Classification of Emergency Conditions at Unit 2"

EPIP -

EPP -01, Attachment 1, "Emergency Action Level Matrix/Unit 1"

EPIP -

EPP -02, Attachment 1, "Emergency Action Level Matrix/Unit 2"

EPMP -

EPP-0101, "Unit 1 Emergency Classification Technical Bases"

N2-SOP-101D, "Rapid Power Reduction"

N2-SOP-08, "Unplanned Power Changes"

N1-EOP-C5, "Failure to Scram"

EPMP -

EPP -0102, "Unit 2 Emergency Classification Technical Bases"

NMP Simulator Scenario, O2-

OPS-009-1DY-2-63, "Feedwater Heater Tube Bundle Leak with

Control Rod Drift/Steam Line Break/ATWS"

NMP Simulator Scenario O1-

OPS-009-1DY-1-57, "Feedwater Pump Trip, Turbine Vibrations,

Steam Leak in Containment"

N2-EOP-PC, "Primary Containment Control"

N1-EOP-4, "Primary Containment Control"

Section 1R12: Maintenance Rule ImplementationNine Mile Point

MR Category (a)(1) Summary ReportUnit 1

MR Integrated Scoping Matrix

Unit 1 MR Integrated Performance Criteria Matrix

Unit 1 MR Integrated Performance Criteria Matrix - Super Systems

Unit 1 MR High Safety Significant Functions and Related Key Safety Functions

Unit 1 MR Function Report - Emergency Cooling

Unit 2 MR Integrated Scoping Matrix

Unit 2 MR Integrated Performance Criteria Matrix

Unit 2 MR Integrated Performance Criteria Matrix - Super Systems

Unit 2 MR High Safety Significant Functions and Related Key Safety Functions

Unit

2 MR Function Report -

HVP - Diesel Generator Ventilation System

A-5AttachmentNMP -

MR Category (a)(1) Detailed progress report for Unit 2 diesel generator ventilationsystem motor operated damper failures

SDBD -204, "Emergency Cooling System

DBD "

CR -2006-0014, Division 2 diesel generator motor operated damper 2

HVP*MOD1B failed to

close as designed

CR -2007-0512, 2

HVP *AOD4D took 30 minutes to close after fan secured

NMP -

MR Category (a)(1) Summary Report for Unit 2 diesel generator ventilation system

motor operated damper failures

CR -2002-0447, Division 2

EDG emergency ventilation discharge damper failure

CR -2006-4881,

HVP *MOD2B failed to operate during Division

III [[]]

EDG run

CR -2004-4736, 2

HVP *MOD1B was identified as failed under ACR 04-09038

WO 06-04877-00, Inspect electrical control box on

HVP dampersSection 1R13: Maintenance Risk Assessments and Emergent Work EvaluationGAP-OPS-117, "Integrated Risk Management"GAP-PSH-03, "Control of On-line Work Activities"

NAI -

PSH -03, "On-line Work Management Process"

WO 04-17071-00, 2

SWP *MOV1F, Limitorque actuator static testing

WO 05-01272-00, 2

SWP *V1F, Inspect and flush hinge pin bearing areas

WO 05-02332-00, 2

SWP *STR4F, Service water strainer preventative maintenance

WO 06-08759-00, 2

CSH *STRT1, Temporary strainer needs to be removed per specifications

WO 05-01961-00, Perform online motor testing for 2

CSH *M1

WO 05-12874-00, 2

EGS *E1C is degraded and needs to be replaced

WO 05-02566-00, S-

RCPM -GEN-062, HFA Armature Test and Calibration, 10 yr inspection

WO 05-02579-00, N2-

RCPM -GEN-V070, Protective/Auxiliary relays and timers

WO 05-20370-00, N2-

EPM -EGS-V656, 2600 kW

HP [[]]

CS Diesel Generator and auxiliary

equipment

WO 05-22434-00, N1-

MPM -100-851, Diesel fire pump engine preventative maintenance

WO 06-20636-00,

ENG-100-01, engine speed needs to be increased

N1-ST-M4A, "Emergency Diesel Generator 102 and PB 102 Operability Test"

N1-ST-Q16A,"Emergency Diesel Generator 102 Quarterly Test

WO 06-03769-00,

BV-68-02, disassemble and rebuild actuator, replace o-rings, gaskets, seal

WO 07-01341-00, Re-brush and re-clean main generator amplidyne

N2-ISP-ISC-Q017, "Quarterly Functional Test of Feedwater/Main Turbine Trip on Reactor

Vessel Water High Level 8 Instrument Channels"

N2-OSP-EGS-M@001, "Diesel Generator and Diesel Air Start Valve Operability Test - Division I

and

II "

WO 06-03168-00, N2-

MPM -IAS-V606 Instrument Air Compressor PM

WO 02-10910-00, Rosemount transmitter 2

ICS*PDT168 susceptible to excess instrument drift

and requires replacement

WO 05-25163-00, Operating cycle channel calibration of

RCIC steam line flow high instrument

channel

N2-ISP-ICS-R121, "Operating Cycle Channel Calibration Including Isolation Time Delay"

WO 06-03417-00, Perform condensate filter cleaning and discharge

SOV maintenance, and

replace pre-filter cartridge

N2-OSP-RHS-M001, "RHR Discharge Piping Fill (LPCI) and Valve Lineup Verification"

A-6AttachmentN2-ISP-RHS-Q022, "Quarterly Functional Test of the

RHR Pump Discharge Flow InstrumentChannels"

WO 05-01120-00, 2

SWP *AOV20A Spring return actuator maintenance

WO 06-01009-00, 2

RHS *MOV8A, limitorque MOV testing

WO 06-12932-00, Install pomona jacks in 2

CEC*PNL629 defeat high drywell pressure interlock

N2-ISP-ISC-Q003, Quarterly Functional Test of the Reactor Vessel Water Level Low Low Level

and the Reactor Vessel Low Low Low Water Level 1 Instrument Channels"

N2-OSP-CSL-M001, "LPCS Discharge Fill And Valve Line-up Verification"

N1-ST-Q1A, "CS 111 Pump and Valve And

SDC Water Seal Check Valve Operability Test"

WO 05-24037-01, Replace R915 per

ESR 05-02712 and ESR 05-3333, this work is to be

performed pre-outage

WO 06-04060-00, N1-

ST-M4A, "Emergency Diesel Generator 102 and PB 102 Operability

Test"

ACR 07-00979, During N1-

ST-M4A surveillance when the control switch was taken to stop, not

minute cooldown

CR 2007-0948, Unexpected response during N1-

ST-M4A when EDG 102 control switch taken

to shutdown position no 3 minute cooldown

N1-ST-Q28, "Containment Spray Raw Water Inter Tie Check Valve Quarterly Operability Test"

Nine Mile Point Site T-0 System Schedules, Schedule Risk Assessment Summary Tables, and

PRA Work Week Summaries for work weeks 702-705 and 710Section 1R15: Operability EvaluationsEmail dated 01/16/2007, D. Pelton to L. Cline regarding recent event at Monticello

IMC Part9900 Technical Guidance, "On-line Leak Sealing Guidelines for

AS [[]]

ME Code Class 1 and 2

Components"

ACR 06-06587, Hinge Pin cover leaking approximately 100 drops per minute

Design Change Package (DCP) No. N2-01-203, Check Valve Internals Modification

2FWS *

AOV23A/B

Dwg No. 0005360170408, 24 inch, 900 lb., Swing Check Valve Weld Ends Carbon Steel with

Anti-Rotating Disc

Nine Mile Point Nuclear Station Unit 2 Calculation No. A10.1-E-116, Air Leakage Rate to Water

Leakage Rate Correlation

Wylie Laboratories, Wylie Certification Test Report No. 17761-1, report prepared for Public

Service Electric & Gas Company, Hope Creek Generating Station, Hancocks Bridge, NJ,

November 6, 1983

TCP No. N2-06-091, Leak Seal for 2

FWS*V23B

WO 06-22403-00, Unit 2, Hinge pin cover is leaking approximately 100 drops per minute

CR 2006-5855, Leakage from 2

FWS*23B hinge pin cover found during steam tunnel walkdown

O1-OPS-001-215-1-02, Neutron Monitoring System

O1-OPS-001-212-1-01, Reactor Protection System

N1-OP-38C, "Local Power Range Monitors (LPRM) Average Power Range Monitors"

A-7AttachmentSection 1R19: Post Maintenance TestingWO 06-11287-00WO 07-01313-00

WO 05-02332-00

WO 05-01272-00

ACR 06-5782

N2-ISP-RPS-R211, "Channel Scram Response Time Test"

N2-OSP-RPS-W002, "Manual Scram Channel Functional Test"

N2-OSP-SWP-Q002, "Service Water Pump and Valve Operability Test"

N2-OSP-SWP-Q004, "Division 2 Service Water Operability Test"

N2-OSP-RHS-Q003, "RHR System Loop C Valve Operability Test"

GAP -

SAT -02, "Pre/Post-Maintenance Test Requirements"

CNG -

HU -1.01, "Human Performance Program"

CNG -

HU -1.01-1000, "Human Performance"

CNG -

HU -1.01-1001, "Human Performance Tools and Verification Practices"

GAP -

MAI-01, "Conduct of Maintenance"

N1-ST-R11, "Valve Remote Position Indicator Verification" completed January 24, 2007

N1-ST-SA6, "Drywell/Torus and Torus/RB Vacuum Reliefs Test" completed January 24, 2007

N1-MMP-068-251, "Maintenance of Containment Vacuum Relief Valves"

N1-PM-W9, "Fire Protection System - Weekly Operation of Fire Pumps" completed January 26,

2007

N1-MPM-100-851, "Diesel Fire Pump Engine Preventative Maintenance"

N2-ISP-LRT-R@102, "Type "C" Containment Isolation Valve Vacuum Leak Rate Test

2FWS *V12A, 2

FWS *V12B,

2FWS *V23A, 2

FWS*V23B" completed on March 12, 2007

N2-IPM-LRT-@001, "Leak rate Monitor Flow and Electrical Integrity Check"

N2-OP-3, "Condensate and Feedwater System"Section 1R20: Refueling and Outage ActivitiesCNG-HU-1.01, "Human Performance Program"CNG-HU-1.01-1000, "Human Performance"

CNG -

HU -1.01-1001, "Human Performance Tools and Verification Practices"

CNG -

HU -1.01-1002, "Pre-Job and Post-Job Critiques"

GAP -

OPS-117, "Integrated Risk Management"

S-RPIP-10.4, "Primary Containment Entries"

N1-FHP-27C, "Core Shuffle"

N1-FHP-25, "General Description of Fuel Moves"

N1-ODP-NFM-101, "Refueling Operations"

N1-ODP-OPS-0108, "Shutdown Operations Protection"

N1-OP-34, "Refueling Procedure"

N1-OP-43C, "Plant Shutdown"

N1-OP-4, "Shutdown Cooling System"

N2-OP-101C, "Plant Shutdown"

N2-OP-101A, "Plant Start-up"

N2-OSP-RCS-@001, "RCS Pressure/Temperature Verification"

A-8AttachmentSection 1R22: Surveillance TestingN2-ISP-LDS-Q007, "Quarterly Functional Test of

RHR Equipment Area and General

RB AreaTemperature Instrument Channels

2RHS *

TE 49A,

2RHS *

TE 49B,

2RHS *

TE49C, and2RHS*TE49D"

N1-ST-Q6C, "Containment Spray System Loop 112 Quarterly Operability Test"

N2-OSP-RHS-Q@006, "RHR System Loop C Pump and Valve Operability Test and System

Integrated Test"

N1-ST-Q1B, "CS [Core Spray] 121 Pump, Valve and SDC [Shutdown Cooling] Water Seal

Check Valve Operability Test"

N1-ST-R9, "Core Spray Operability Test Using Demineralized (CST) Water"

CNG -

HU -1.01, "Human Performance Program"

CNG -

HU -1.01-1000, "Human Performance"

CNG -

HU -1.01-1001, "Human Performance Tools and Verification Practices"

GAP -

SAT -01, "Surveillance Test Program"

CNG -

HU -1.01-1002, "Pre-Job and Post-Job Critiques"

GAP -

OPS -117, "Integrated Risk Management"

NMPNS Unit 1 Calculation No. 4.16

VAC-DG-ES, D.G. Loading

N1-ST-M4A, "EDG 102 and PB 102 Operability Test" completed on January 22, 2007

N1-OP-33A, "115 kV System"

N2-OSP-CSH-Q@002, "HPCS Pump and Valve Operability and System Integrity Test"

completed on January 25, 2007

N2-OP-100B, "HPCS Diesel Generator"

N2-OSP-EGS-M@002, "Diesel Generator and Diesel Air Start Valve Operability Test - Division

III " completed January 27, 2007Section 1R23: Temporary Plant Modifications

IMC Part 9900 Technical Guidance, "On-line Leak Sealing Guidelines for

AS [[]]

ME Code Class 1and 2 Components"

ACR 06-06587, Hinge Pin cover leaking approximately 100 drops per minute

Design Change Package (DCP) No. N2-01-203, Check Valve Internals Modification

2FWS *

AOV23A/B

Dwg No. 0005360170408, 24 inch, 900 lb., Swing Check Valve Weld Ends Carbon Steel with

Anti-Rotating Disc

Nine Mile Point Nuclear Station Unit 2 Calculation No. A10.1-E-116, Air Leakage Rate to Water

Leakage Rate Correlation

Wylie Laboratories, Wylie Certification Test Report No. 17761-1, report prepared for Public

Service Electric & Gas Company, Hope Creek Generating Station, Hancocks Bridge, NJ,

November 6, 1983

TCP No. N2-06-091, Leak Seal for 2

FWS*V23B

WO 06-22403-00, Unit 2, Hinge pin cover is leaking approximately 100 drops per minute

CR 2006-5855, Leakage from 2

FWS*23B hinge pin cover found during steam tunnel walkdown

A-9AttachmentSection

1EP 6: Drill Evaluation

NEI 99-02,

PI Guidelines, Revision 2

CNG -HU-1.01, "Human Performance Program"

CNG -

HU -1.01-1000, "Human Performance"

CNG -

HU-1.01-1001, "Human Performance Tools and Verification Practices"

S-ODP-OPS-0001, "Conduct of Operations"

EPIP -

EPP -01, "Classification of Emergency Conditions at Unit 1"

EPIP -

EPP -17, "Emergency Communications Procedure"

EPIP -

EPP-20, "Emergency Notifications"

Emergency Preparedness Scenario for the

EP Drill to be Conducted on March 1, 2007Section 4

OA2: Identification and Resolution of ProblemsCondition Reports2004-00102006-0014

2007-0512

2004-4736

2006-4881

2004-4977

2005-1494

2007-1464

2007-1540

2003-1306

2003-1064

2007-1477

2007-1695

2007-1905

2007-1786

2007-0181

2007-0421

2007-0392

2007-02112007-08382007-0869

2007-0870

2007-1090

2007-0393

2007-0547

2007-1179

2007-1181

2007-0236

2007-0358

2007-1821

2006-3145

2007-0558

2007-1403

2007-0547

2007-0480

2007-0181

2007-0311

2006-58832006-58772007-0052

2007-0011

2006-5855

2006-0026

2007-0355

2007-0414

2007-0430

2007-0448

2007-0552

2007-0625

2007-0653

2007-0667

2007-0730

2007-0722

2007-0727

2007-0838

2007-08692007-09002007-1179

2007-1187

2007-1180

2007-1192

2007-1181

2007-1191

2007-1059

2007-1100

2007-0948

2007-0962

2007-1208

2007-1370

2007-1405

2007-1574

2007-1540

2007-1464Section

4OA 3: Event Follow-upOffsite Dose Calculation ManualN1-

CSP -V304, "Setup/Shutdown of Auxiliary Sampling Equipment"

NMP 1

OGESMS Alternate Monitoring Plan

N2-SOP-29.1, "RRP Seal Failure"

N2-SOP-29, "Sudden Reduction in Core Flow"

CR -2006-2691, Tech Spec required plant shutdown due to increasing

RCS leakage rate

A-10AttachmentLIST

OF [[]]

ACRONYMSADAMSAgencywide Document and Management SystemASMEAmerican Society of Mechanical Engineers

CAPcorrective action program

CRcondition report

DBDdesign basis documents

ECemergency cooling system

EDGemergency diesel generator

EOP emergency operating procedure

GT [[]]

AWgas tungsten arc welding

IMC inspection manual chapter

IPE [[]]

EEindividual plant examination of external events

ISIinservice inspection

kVkilovolt

LO [[]]

RTlicensed operator requalification training

MTmagnetic particle test

MRmaintenance rule

NCVsnon-cited violations

NDE non-destructive examination

NMPN [[]]

SN ine Mile Point Nuclear Station

NR [[]]

CN uclear Regulatory Commission

OD [[]]

CM offsite dose calculation manual

OGES [[]]

MSoff-gas effluent stack monitoring system

OP operating procedure

PA [[]]

RSpublicly available records

PQRprocedure qualification record

PRAprobabilistic risk assessment

PTpenetration test

RB reactor building

RBC [[]]

LC reactor building closed loop cooling

RC [[]]

ICreactor core isolation cooling

RCSreactor coolant system

RHRresidual heat removal

RPVreactor pressure vessel

RRP reactor recirculation pump

RW [[]]

CUreactor water clean up

SBO station blackout

SM [[]]

AW shielded metal arc welding

SP [[]]

AR standardized plant analysis risk

SR [[]]

ASenior Reactor Analyst

SSCstructures, systems, or components

STsurveillance test

TCPtemporary change packages

TS technical specification

UFSA [[]]

RUpdated Final Safety Evaluation Report

UTultrasonic test

Vdcvolts direct current

VTvisual examination

WO work order