IR 05000220/2007002
| ML071200236 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 04/27/2007 |
| From: | Blake Welling Reactor Projects Branch 2 |
| To: | Nietmann K Nine Mile Point |
| Welling B, RGN-I/DRP/PB1, 610-337-5328 | |
| References | |
| IR-07-002 | |
| Download: ML071200236 (33) | |
Text
April 27, 2007Mr. Kevin J. NietmannActing Vice President Nine Mile Point Nine Mile Point Nuclear Station, LLC P.O. Box 63 Lycoming, NY 13093SUBJECT: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-69Enclosure: 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
IR 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 NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006. A.
NRC-Identified and Self-Revealing Findings
Cornerstone: 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 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 and the unavailability of RCIC for approximately four hours. Operators immediately recognized the error and halted the surveillance procedure. Technicians reconnected the thermocouple, and operators restored RCIC 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 Violations
None.
Enclosure
REPORT DETAILS
Summary 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 RFO19, 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 SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
a. Inspection Scope
The 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 NMPNS 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. Findings
No 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 UFSAR. 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. Findings
No 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.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05Q - 13 samples)
a. Inspection Scope
The inspectors completed 13 quarterly fire protection inspection samples. Theinspectors toured 13 areas important to reactor safety at the station to evaluate NMPNS'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;
b. Findings
No findings of significance were identified.
1R08 Inservice Inspection Activities (71111.08 - 9 samples)
a. Inspection Scope
The 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 NMPNS 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 ASME Code and 10 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 2EGS*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 CRs 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. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11Q - 2 samples)
a. Inspection Scope
The inspectors completed two licensed operator requalification training program (LORT)inspection samples. Documents reviewed for this inspection are listed in the
. 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 LORT 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 LORT 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 EOPs, N1-EOP-C5, "Failure to Scram," and N2-EOP-PC, "Primary Containment Control."
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12Q - 2 samples)
a. Inspection Scope
The 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. Findings
No 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.
1R15 Operability 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 TSs, UFSAR, 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,LPRM28-25C, 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. Findings
No findings of significance were identified.
9Enclosure1R19Post Maintenance Testing (71111.19 - 8 samples)
a. Inspection Scope
The 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 TSs, 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, 2FWS*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, WOs 05-02332-00 and 05-01272-00 that performed maintenance onservice water pump 'F' discharge strainer, 2SWP*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 - Divis ion III."
b. Findings
No findings of significance were identified.
1R20 Refueling 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 NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management," and NMPNS 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. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22 - 8 samples)
a. Inspection Scope
The inspectors completed eight quarterly surveillance testing inspection samples. Theinspectors witnessed performance of and/or reviewed test data for eight risk-significant STs to assess whether the SSCs tested satisfied TS, UFSAR, Technical Requirements Manual, and NMPNS 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 STs were reviewed:*N2-ISP-LDS-Q007, "Quarterly Functional Test of RHR Equipment Area andGeneral RB Area Temperature Instrument Channels 2RHS*TE49A, 2RHS*TE49B, 2RHS*TE49C, 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;"
12Enclosure*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 RHREquipment Area and General RB Area Temperature Instrument Channels 2RHS*TE49A, 2RHS*TE49B, 2RHS*TE49C, 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 RCIC steam supply.
Operators immediately recognized the error and halted the surveillance procedure.
Technicians reconnected the thermocouple, and operators restored RCIC to a normal standby lineup. During the four hours that the RCIC 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 SPAR 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 SPAR 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*TE49A, 2RHS*TE49B, 2RHS*TE49C, 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:
NCV05000410/2007002-01, Failure to Follow Procedure Caused Inadvertent Isolation of RCIC Steam Supply
.1 R23Temporary Plant Modifications
a. Inspection Scope
The 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. Findings
No findings of significance were identified. Cornerstone: Emergency Preparedness1EP6Drill 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. Findings
No findings of significance were identified.
15Enclosure4.OTHER ACTIVITIES4OA2Identification and Resolution of Problems.1Review of Items Entered into the CAP
a. Inspection Scope
As 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 CRs 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 NMPNS'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 CRs reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.4OA3Event 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 OGESMS 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 ODCM stack sampling requirements for noble gas, particulate, and iodine.
The ODCM did not specify actions if both the normal and auxiliary sampling systems were unavailable. Therefore, in response to the event, NMPNS 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. NMPNS 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. NMPNS attempted to clear the obstruction using heated pressurized nitrogen. On January 27, 2007, this method was successful, and OGESMS 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 NMPNS's ability to implement their emergency plan, as well as its effects on public radiation safety.
b. Findings
No 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.
NMPNS 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. Findings
No findings of significance were identified.4OA5Other Activities.1(Closed) URI 05000220/2006008-03 PRA Assumptions Regarding SBO Coping Time
a. Inspection Scope
This 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. Findings
No findings of significance were identified..2Review of the Institute of Nuclear Power Operations 2006 Evaluation
a. Inspection Scope
The 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 NMPNS's performance and to identify significant safety issues that required NRC follow-up.
b. Findings
No findings of significance were identified.4OA6Meetings, 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:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- N. Conicella, Manager, Operations
- R. 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 DISCUSSED
Opened and
Closed
05000410/2007002-01NCVFailure to Follow Procedure CausedInadvertent Isolation of RCIC Steam Supply
(Section 1R22)
Closed
05000220/2006008-03URIPRA Assumptions Regarding SBO CopingTime (Section 4OA5)