IR 05000220/2009004

IR 05000220-09-004, 05000410-09-004; 07/01/2009 - 09/30/2009; Nine Mile Point Nuclear Station, Units 1 and 2; Identification and Resolution of Problems

ML093070020
Person / Time
Site:	Nine Mile Point
Issue date:	11/02/2009
From:	Glenn Dentel Reactor Projects Branch 1
To:	Belcher S Nine Mile Point
Dentel, G RGN-I/DRP/BR1/610-337-5233
References
FOIA/PA-2010-0209 IR-09-004
Download: ML093070020 (34)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ber 2, 2009

SUBJECT:

NINE MILE POINT NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000220/2009004 AN D 05000410/2009004

Dear Mr. Belcher:

On September 30,2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Nine Mile Point Nuclear Station Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on October 9, 2009, with you and members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified finding of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance and because it is entered into your corrective action program (CAP), the NRC is treating the finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S.

Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555 0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Senior Resident Inspector at Nine Mile Point Nuclear Station. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Senior Resident Inspector at Nine Mile Point Nuclear Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305. In accordance with 10 CFR Part 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rrn/adams.html(the Public Electronic Reading Room).

Sincerely, IRA!

Glenn 1. Dentel, Chief Projects Branch 1 Division of Reactor Projects Docket Nos.: 50-220,50-410 License Nos.: DPR-63, NPF-69 Enclosure: Inspection Report 05000220/2009004 and 05000410/2009004 w/Attachment: Supplemental Information cc w/encl: Distribution via ListServ

SUMMARY OF FINDINGS

IR 05000220/2009004; 05000410/2009004; 07/01/2009 - 09/30/2009; Nine Mile Point Nuclear

Station, Units 1 and 2; Identification and Resolution of Problems.

The report covered a three-month period of inspection by resident inspectors, and announced inspections and an in-office inspection performed by regional inspectors. One Green finding, which was a non-cited violation (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 (SOP)." The cross cutting aspect for the finding was determined using IMC 0305, "Operating Reactor Assessment Program." Findings for which the SOP 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.

Cornerstone: Mitigating Systems

Green.

An NRC-identified non-cited violation (NCV) of 10 CFR Part 50, Appendix B. Criterion III, "Design Control," was identified, in that Nine Mile Point Nuclear Station (NMPNS) failed to maintain the Unit 2 high pressure core spray (HPCS) pump power cables in an environment for which they were designed. Although NMPNS had indications that these cables were periodically submerged in water, they could not demonstrate that the cables were designed for submerged conditions. As immediate corrective action, NMPNS dewatered and inspected the HPCS cable run, and changed the frequency of dewatering to monthly. Based on the inspection results, along with the cable design specifications and most recent test results,

NMPNS concluded that the HPCS pump power cables would remain operable while they conduct a design change evaluation to examine methods to reduce cable exposure to submerged conditions. The issue was entered into the corrective action program (CAP) as condition report (CR) 2009-2901.

The finding was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. The finding affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because it was a qualification deficiency that did not result in loss of operability. The finding had a cross-cutting aspect in the area of problem identification and resolution, operating experience, because NMPNS did not use operating experience, such as Generic Letter (GL) 2007-01, "Inaccessible or Underground Power Cable Failures That Disable Accident Mitigation Systems or Cause Plant Transients," to evaluate possible adverse effects of periodic submergence of the HPCS pump power cables (P.2.a per IMC 0305). (Section 40A2)

Other Findings

None.

REPORT DETAILS

Summary of Plant Status

Nine Mile Point Unit 1 began the inspection period at full rated thermal power (RTP). On September 12, power was reduced to 92 percent to secure reactor recirculation pump (RRP) 13 to install new brushes in its associated motor-generator (MG), and later to 85 percent to return the pump to service. Quarterly turbine valve testing was also performed while at reduced power.

Power was restored to full RTP later that day. On September 26, power was reduced to 92 percent to secure RRP 12 for work on its associated MG. Power was restored to full RTP later that day and remained there for the rest of the inspection period.

Nine Mile Point Unit 2 began the inspection period at full RTP. On July 13, power was reduced to 60 percent to swap operating reactor feedwater pumps (RFPs) due to through-wall leakage from the 'A' RFP minimum flow valve. Power was restored to full RTP later that day. On September 19, power was reduced to 65 percent for a control rod sequence exchange, control rod stroke timing and adjustment, quarterly turbine valve testing, and to perform a temporary leak repair on the 'A' RFP minimum flow valve. Power was restored to full RTP the following day and remained there for the rest of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Occurrences of Adverse Weather (One sample)

a. Inspection Scope

On August 20,2009, the inspectors reviewed NMPNS's actions in response to a short noticed electrical storm in the vicinity of the station. During this storm, a lightning strike caused a brief loss of Unit 1 off-site 115 kilovolt (KV) supply line 1. Off-site power continued to be supplied to Unit 1 via the other 115 KV supply line (line 4), and line 1 was restored to service by operation of the automatic reclosure feature of the affected circuit breaker (R1 0), 36 seconds later. The voltage transient caused by the lightning strike caused a loss of the operating control room chilled water pump and associated ventilation chillers, but had no other significant impact on plant operations. Unit 2 was not affected by the lightning strike. The inspectors verified that plant operators responded appropriately to the storm and observed that actions to verify plant status following the lightning strike were thorough.

b. Findings

No findings of significance were identified.

.2 Readiness to Cope with External Flooding (One sample)

a. Inspection Scope

The inspectors reviewed the individual plant examinations and updated final safety analysis reports (UFSARs) for Units 1 and 2 concerning external flooding events at the site. The inspection included a walkdown of accessible areas of each unit's perimeter to look for potential susceptibilities to external flooding and to verify the assumptions included in each unit's external flooding analysis. The inspectors also reviewed relevant abnormal and emergency plan (EP) procedures.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdown (71111.040 - Four samples)

a. Inspection Scope

The inspectors performed partial system walkdowns to verify risk-significant systems were properly aligned for operation. The inspectors verified the operability and alignment of these risk-significant systems while their redundant trains or systems were inoperable or out of service for maintenance. The inspectors compared system lineups to system operating procedures, system drawings, and the applicable chapters in the UFSAR. The inspectors verified the operability of critical system components by observing component material condition during the system walkdown.

The following plant system alignments were reviewed:

• Unit 1 containment spray system 11 (111 and 112) due to increased risk significance during maintenance on containment spray system 121;

• Unit 1 core spray system 11 (111 and 112) due to increased risk significance during maintenance on core spray system 122;

• Unit 2 'B' residual heat removal (RHR) system due to increased risk significance during maintenance on the 'A' RHR system; and

• Unit 2 Division 1 standby gas treatment (SBGT) system due to increased risk significance during maintenance on the Division 2 SBGT system.

b. Findings

No findings of significance were identified .

.2 Complete System Walkdown (71111.04S - One sample)

a. Inspection Scope

The inspectors performed a complete walkdown of the Unit 1 reactor core isolation cooling (RCIC) system to identify discrepancies between the existing equipment con'figuration and that specified in the design documents. During the walkdown, system drawings and operating procedures were used to determine the proper equipment alignment and operational status. The inspectors reviewed the open maintenance work orders (WOs) that could affect the ability of the system to perform its functions. Documentation associated with 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.

b. Findings

No findings of significance were identified.

'I

R05 Fire Protection

Routine Resident Inspector Tours (71111.050 - Six samples)

a. Inspection Scope

The inspectors toured areas important to reactor safety to evaluate the station's control of transient combustibles and ignition sources, and to examine the material condition, operational status, and operational lineup of fire protection systems including detection, suppression, and fire barriers. The inspectors evaluated fire protection attributes using the criteria contained in Unit 1 UFSAR Appendix 10A, "Fire Hazards Analysis," and Unit 2 procedure N2-FPI-PFP-0201, "Unit 2 Pre-Fire Plans." The areas inspected included:

• Unit 1 core spray 11 corner room, reactor building (RB) 198, 218, and 237 foot elevations;

• Unit 1 containment spray 11 corner room, RB 198 and 218 foot elevations;

• Unit 1 refueling floor, RB 340 foot elevation;

• Unit 2 north auxiliary bay, RB 196,215, and 240 foot elevations;

• Unit 2 RB 289 foot elevation; and

• Unit 2 Division 2 switchgear room, control building 261 foot elevation.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06 - Two samples)

.1 Unit 1 Screen Well

a. Inspection Scope

The inspectors examined the susceptibility of the Unit 1 screen well (lake water intake structure) to internal flooding. The inspectors reviewed the individual plant examination and the UFSAR to evaluate potential flooding scenarios and their risk Significance. The inspectors performed a walkdown of the Unit 1 screen well to look for sources of potential flooding that were not analyzed or not adequately maintained.

b. Findings

No findings of significance were identified .

.2 Unit 2 Turbine Building to Reactor Building

a. Inspection Scope

The inspectors reviewed Unit 2 flood analysis and design documents including the UFSAR for licensee commitments, and reviewed drawings to identify areas and equipment that may be affected by internal flooding due to a rupture of the circulating water or service water (SW) systems from the turbine building to the reactor building. The review focused on the maintenance requirements and material condition of silicon rubber seals for pipes that penetrate the reactor building at elevation 208 feet from a turbine building pipe tunnel.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Regualification Program

Quarterly Review (71111.11 Q - Two samples)

a. Inspection Scope

The inspectors evaluated two simulator scenarios in the licensed operator requalification training (LORT) program. 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 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 scenarios were observed:

• On August 11, 2009, the inspectors observed Unit 1 LORT to assess operator and instructor performance during a scenario involving a seismic event that resulted in a loss of power board 17A and drywell cooling, a reactor feedwater line break in the turbine building, a reactor water cleanup line break, and failure of a liquid poison pump.

The inspectors evaluated the performance of risk significant operator actions including the use of special operating procedures (SOPs) and emergency operating procedures (EOPs).

• On August 18, 2009, the inspectors observed Unit 2 LORT to assess operator and instructor performance during a scenario involving failure of a drywell unit cooler, automatic isolation of the reactor water cleanup and RCIC systems due to a reactor coolant leak detection system failure, loss of a reactor recirculation system pump, and a small-break loss of coolant accident, in the drywell coincident with a failure of the Division 3 electrical system that led operators to perform a reactor pressure vessel (RPV) blowdown. The inspectors evaluated the performance of risk significant operator actions including the use of SOPs and EOPs.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12 - Three samples)

a. Inspection Scope

The inspectors reviewed performance-based problems, and the performance and condition history of selected systems to assess the effectiveness of the maintenance program. The inspectors reviewed the systems to ensure that the station's review focused on proper maintenance rule scoping in accordance with 10 CFR Part 50.65, characterization of reliability issues, tracking system and component unavailability, and 10 CFR Part 50.65(a)(1) and (a)(2) classification. In addition, the inspectors reviewed the site's ability to identify and address common cause failures, and to trend key parameters. The following maintenance rule inspection samples were reviewed:

• Unit 1 automatic depressurization system due to electromatic relief valve 122 seat leakage;

• Unit 2 standby liquid control system due to pump performance issues; and

• Unit 2 reactor feedwater system due to pump recirculation valve issues.

b. Findings

No findings of significance were identified.

1R 13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - Six samples)

a. Inspection Scope

The inspectors evaluated the effectiveness of the maintenance risk assessments required by 10 CFR Part 50.65(a)(4). The inspectors reviewed equipment logs, work schedules, and performed plant tours to verify that actual plant configuration matched the assessed configuration. Additionally, the inspectors verified that risk management actions for both planned and emergent work were consistent with those described in station procedures.

The inspectors reviewed risk assessments for the activities listed below.

• Week of July 27, that included liquid poison pump 11 and 12 cycle (24 month)surveillances, control rod drive system quarterly surveillance, emergency service water quarterly surveillance, reactor protection system (RPS) uninterruptible power supply (UPS) 172B maintenance, instrument air compressor 12 maintenance, and emergent maintenance to repair the valve positioner for the feedwater heater 132 level control valve.

• Week of September 14, that included channel 11 recirculation flow loop and flow converter calibrations, a three day maintenance period for the diesel fire pump, maintenance on RPS MG 162B, calibration of anticipated transient without scraml alternate rod insertion (ATWS/ARI) instruments, and emergent maintenance to troubleshoot containment spray raw water inter~tie check valve 93-60 which was not fully seating.

• Week of September 21, that included containment spray system 111 and 121 quarterly surveillances, main steam isolation valve (MSIV) and feedwater isolation valve partial stroke testing, emergency diesel generator (EDG) 102 monthly surveillance, service water system biocide treatment, stator water cooling pump 12 maintenance, and a power reduction to 92 percent to secure RRP 12 for maintenance on its associated MG.

• Week of July 27, that included 'C' instrument air compressor overhaul, 'B' RHR quarterly surveillance, 'B' standby liquid control (SLC) maintenance and quarterly surveillance, Division 2 EDG monthly surveillance, a two day maintenance period for the Division 2 SBGT system, 'B' reactor building closed loop cooling booster pump mechanical seal replacement and troubleshooting for high vibrations, and emergent maintenance to correct the cause of a loss of the 'B' RPS MG and to replace a broken shear pin for the 'F' SW pump discharge strainer.

• Week of August 3, that included RCIC system quarterly surveillance, overhaul of the 'C' instrument air compressor, repair of the 'F' SW pump outboard pump bearing housing, replacement of transponder cards in the reactor manual control system, and emergent maintenance to replace the supply breaker for the 'A' RPS MG.

• Week of September 14, that included low pressure core spray system maintenance and quarterly surveillance, 'A' SLC system quarterly surveillance, 'A' SBGT system maintenance, and a power reduction to 65 percent for a control rod pattern exchange, turbine valve testing, and temporary repair of a through-wall leak from the 'A' RFP minimum flow valve.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15 ~ Seven samples)

a. Inspection Scope

The inspectors evaluated the acceptability of operability evaluations, the use and control of compensatory measures, and compliance with technical specifications (TSs). The evaluations were reviewed using criteria specified in NRC Regulatory Issue Summary 2005-20, "Revision to Guidance Formerly Contained in NRC Generic Letter (GL) 91-18,

'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability'," and Inspection Manual Part 9900, "Operability Determinations and Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety." The inspectors' review included verification that the operability determinations were made as specified by Procedure CNG-OP-1.01-1002, "Conduct of Operability Determinations I Functionality Assessments." The technical adequacy of the determinations was reviewed and compared to the TSs, UFSAR, and associated design basis documents (DBDs). The following evaluations were reviewed:

• CR 2009-4100 concerning the effect of non-conservative test methodology used for Unit 1 diesel fire pump flow testing on the pump's ability to provide design basis flow;

• CR 2009-4137 concerning Unit 2 emergency core cooling system suction strainer operability in light of vendor testing that indicated higher than expected post-accident head loss due to debris loading;

• CR 2009-4230 concerning the operability of numerous Unit 1 safety related motor operated valves pending inspection for a generic issue with a breaker opening coil electrical lead becoming disconnected;

• CR 2009-4537 concerning the operability of four Unit 2 safety relief valves that had exceeded their six year lift test surveillance interval;

• CR 2009-5179 concerning the acceptability of degraded insulation resistance to ground in the Unit 1 electrical circuit breaker that allows safety class 1E power board 17B to be tied to non-safety class power board 17A;

• CR 2009-5421 concerning the effect of increased seat leakage through Unit 1 core spray keep fill system check valve CKV-40-22 on the valve's ability to perform its containment isolation function; and

• CR 2009-6026 concerning Unit 2 containment operability in light of the vendor's determination that post-aCCident peak containment pressure was higher than the current licensing basis value, based on use of a more precise analytical code.

b. Findings

No findings of significance were identified.

1R 18 Plant Modifications (71111.18)

.1 Temporary Modifications (Two samples)

a. Inspection Scope

The inspectors reviewed Unit 2 temporary plant modification, Engineering Change Package (ECP) 09-000053, "Provide Alternate Power to Instrument Air Dryer 2AIS-DRY3B." The purpose of this change was to provide an equivalent replacement for the malfunctioning normal power supply to allow 2AIS-DRY3B to remain available for service. The inspectors reviewed the 10 CFR Part 50.59 screening against the system design bases documentation to verify that the modification did not affect system operability. The inspectors verified the adequacy of acceptance testing and performed a walkdown of the installed modification.

The inspectors reviewed Unit 2 temporary plant modification N2-07-002, "Install Strain Gauges for EPU [extended power uprate] Vibration Monitoring." The strain gages will measure main steam line pressure pulsations that will be used to assess steam dryer performance during implementation of the EPU. The inspectors reviewed the 10 CFR Part 50.59 screening against the system design basis documentation to verify that the modification will not affect system operability.

b. Findings

No findings of significance were identified .

.2 Permanent Modifications (One sample)

a. Inspection Scope

The inspectors reviewed one Unit 1 permanent plant modification, Design Change N1-08 051, "Replace ASCO Scram Solenoid Pilot Valves [SSPVs] with Eugen Seitz SOVs

[solenoid operated valves]." Replacement of the SSPVs was required during this year's refueling outage because the SSPVs were approaching their environmental qualification (EQ) service life limitation. Installation of the modification satisfied the replacement requirement, while also transitioning to components that have a significantly longer EQ service life. The inspectors reviewed the associated 10 CFR Part 50.59 screening against control rod drive system design basis information, including the UFSAR and TS. The inspectors verified that post installation tests were adequate and that NMPNS controlled the modification in accordance with station procedures.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19 - Five samples)

a. Inspection Scope

The inspectors reviewed the post maintenance tests (PMTs) listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure were consistent with information in the applicable licensing basis and/or DBDs, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data, to verify that the test results adequately demonstrated restoration of the affected safety functions.

• Unit 1, WO C90623054 that performed resistance checks on non-vital power board 17A to vital power board 17B tie breaker R1052. The PMT consisted of cycling the breaker closed and open in accordance with N1-0P-30, "4.16KV, 600V, and 480V House Service," Revision 02100.

• Unit 1, WO 09-07571-00 that overhauled containment spray system 111 raw water pump 93-02. The PMT consisted of performing N1-ST-Q6A, "Containment Spray Loop 111 Quarterly Operability Test," Revision 00B01, and N1-PM-V2, "Pump Curve Validation Test," Revision 06.

• Unit 1, WO COB0174900 that repaired instrument air drier 12. The PMT consisted of performing N1-MPM-094-021, "Instrument Air Drier #12 Inspection and Cleaning,"

Revision 02, and a confidence run in accordance with N1-0P-20, "Service, Instrument, and Breathing Air," Revision 02900.

• Unit 1, WO COB1332BOO that installed a new rotating element in diesel fire pump 100 02. The PMT consisted of performing N1-PM-C3, "Electric and Diesel Fire Pump Performance Tests," Revision OB.

• Unit 2, WO COB1515700 that changed the hydraulic fluid backup filter for the 'B' electro-hydraulic control (EHC) system pump. The PMT consisted of placing the 'B' EHC pump in service in accordance with N2-MPM-TMB-Q@451, "Main Turbine Electro Hydraulic Control System Quarterly Inspection," Revision 03.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22 - Four samples)

a. Inspection Scope

The inspectors witnessed performance of and/or reviewed test data for risk-significant surveillance tests (STs) to assess whether the components and systems tested satisfied design and licensing basis 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 test completion, the inspectors verified that equipment was returned to the status specified to perform its safety function.

The following STs were reviewed:

• N1-ISP-036-006, "Emergency Cooling System - High Steam Flow Instrument Trip Channel Test/Calibration," Revision 00501;

• N1-ST-Q1A, "CS [core spray] 111 Pump, Valve and SDC [shutdown cooling] Check Valve Operability Test," Revision 00901;

• N1-ST-SA6, "Drywell/Torus and Torus/Reactor Building Vacuum Reliefs Test," Revision 00; and

• N2-0SP-RHS-Q@006, "RHR System Loop C Pump and Valve Operability Test and System Integrity Test," Revision 00.

This represented a total of four inspection samples, of which three were In-Service Testing and one was a Reactor Coolant System Leakage Detection Surveillance as defined by Inspection Procedure 71111.22.

b. Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06 - One sample)

a. Inspection Scope

The inspectors observed control room operator EP response actions during the Unit 2 evaluated LORT scenario on August 18, 2009. The inspectors verified that emergency classification declarations and notifications were completed in accordance with 10 CFR Part 50.72, 10 CFR Part 50 Appendix E, and emergency plan implementing procedures.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

20S1 Access Control to Radiologically Significant Areas (71121.01 - Six samples)

a. Inspection Scope

The inspectors reviewed radiation work permits (RWP) for airborne radioactivity areas with the potential for individual worker internal exposures of greater than 50 millirem committed effective dose equivalent (20 derived air concentration-hours (DAC-hrs)). For these selected airborne radioactive material areas, the inspectors verified barrier integrity and engineering controls performance (e.g., high efficiency particulate air (HEPA) ventilation system operation).

The inspectors reviewed and assessed the adequacy of the licensee's internal dose assessment for any actual internal exposure greater than 50 mrem committed effective dose equivalent. For 2008 and 2009 (year-to-date), no internal exposures of this magnitude have occurred.

The inspectors examined the licensee's physical and programmatic controls for highly activated or contaminated materials (non-fuel) stored within the spent fuel pools.

The inspectors discussed with the radiation protection manager high dose rate-high radiation area, and very high radiation area controls and procedures. The inspectors focused on any procedural changes since the last inspection. The inspectors verified that any changes to licensee procedures did not substantially reduce the effectiveness and level of worker protection.

The inspectors discussed with health physics supervisors the controls in place for special areas that have the potential to become very high radiation areas during certain plant operations. The inspectors determined if these plant operations required communication beforehand with the health physics group, so as to allow corresponding timely actions to properly post and control the radiation hazards.

The inspectors verified adequate posting and locking of entrances to high dose rate-high radiation areas, and very high radiation areas.

The inspectors evaluated licensee performance against the requirements contained in 10 CFR Part 20, and Unit 1 TS 6.7 and Unit 2 TS 6.12.

b. Findings

No findings of significance were identified.

20S2 ALARA Planning and Controls (71121.02 - Six samples)

a. Inspection Scope

The inspectors reviewed the integration of as low as reasonably achievable (ALARA)requirements into work procedure and RWP documents.

The inspectors compared the person-hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements and evaluated the accuracy of these time estimates.

The inspectors determined if post-job (work activity) reviews were conducted and if identified problems were entered into the licensee's CAP.

The inspectors reviewed the licensee's exposure tracking system. The inspectors determined whether the level of exposure tracking detail, exposure report timeliness and exposure report distribution was sufficient to support control of collective exposures.

During the conduct of exposure significant maintenance work, the inspectors looked for evidence that licensee management was aware of the exposure status of the work and would intervene if exposure trends increased beyond exposure estimates.

The inspectors obtained from the licensee a list of work activities ranked by actual/estimated exposure that were in progress or that had been completed during the last outage and selected the two work activities of highest exposure significance (drywell in service inspection and drywell permanent shielding).

The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors verified that the licensee had established procedures, and engineering and work controls, based on sound radiation protection principles to achieve occupational exposures that were ALARA. The inspectors verified that the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.'

The inspectors compared the results achieved (dose rate reductions, person-rem used)with the intended dose established in the licensee's ALARA planning for these work activities. The inspectors reviewed, where applicable, inconsistencies between intended and actual work activity doses.

The inspectors evaluated licensee performance against the requirements contained in 10 CFR Part 20.1101.

b. Findings

No findings of significance were identified.

20S3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03 - One sample)

a. Inspection Scope

The inspectors reviewed licensee self-assessments, audits and licensee event reports, and focused on radiological incidents that involved personnel contamination monitor alarms due to personnel internal exposures. For internal exposures greater than 50 mrem committed effective dose equivalent, the inspectors determined if the affected personnel were properly monitored utilizing calibrated equipment and if the data was analyzed and internal exposures properly assessed in accordance with licensee procedures. The inspectors determined if identified problems were entered into the CAP for resolution.

The inspectors evaluated licensee performance against the requirements contained in 10 CFR Part 20.1501,10 CFR Part 20.1703, and 10 CFR Part 20.1704.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

40A1 Performance Indicator Verification (71151 -10 samples)

a. Inspection Scope

The inspectors sampled NMPNS submittals for the performance indicators (Pis) listed below. The PI definition guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Indicator Guideline," Revision 5, was used to verify the basis in reporting for each data element and the accuracy of the PI data reported.

Cornerstone: Mitigating Systems

The inspectors reviewed NMPNS's submittals for the Mitigating System Performance Index (MSPI) listed below to determine the accuracy and completeness of the reported data. The review was accomplished by comparing the reported PI data to plant records and information available in plant logs, CRs, system health reports, the respective MSPI Basis Documents, and NRC inspection reports. Operating data for the period of October 2008 through June 2009 were reviewed to complete this inspection.

• Unit 1 emergency alternating current (AC) power system;

• Unit 1 high pressure injection system;

• Unit 1 heat removal system;

• Unit 1 RHR system;

• Unit 1 cooling water systems;

• Unit 2 emergency AC power system;

• Unit 2 high pressure injection system;

• Unit 2 heat removal system;

• Unit 2 RHR system; and

• Unit 2 cooling water systems.

b. Findings

No findings of significance were identified.

40A2 Identification and Resolution of Problems (71152 - Two samples)

.1 Review of Items Entered into the CAP

a. Inspection Scope

As specified by Inspection Procedure 71152, "Identification and Resolution of Problems,"

and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into NMPNS's CAP. In accordance with the baseline inspection procedures, the inspectors also identified selected CAP items across the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones for additional follow-up and review. The inspectors assessed the threshold for problem identification, the adequacy of the cause analyses, extent of condition review, operability determinations, and the timeliness of the specified corrective actions.

b. Findings

No findings of significance were identified .

.2 Annual Sample - Review of Silent Half Scram Events Resulting From Electrical

Protection Assembly Overvoltage Trips While Aligned to Their Alternate Power Source

a. Inspection Scope

The inspectors selected CRs 2007-5394, 2008-4880, and 2008-4884, concerning silent (unalarmed) half scrams at Unit 2, as a problem identification and resolution (PI&R) sample for detailed follow*up review.

Electrical power to the solenoid*operated scram pilot valves is normally provided by two MG sets. One MG set powers the 'A' solenoid valves for all of the scram valves and the other MG set powers all the '8' solenoid valves. When an MG set is out of service for maintenance or repairs its associated solenoid valves can be powered from an alternate AC power source. The power from the MG set or alternate source is monitored and controlled by electrical protective assemblies (EPAs) to ensure the power quality to the solenoid valves is adequate to prevent damage to the valves due to a high voltage, low voltage, or low frequency condition.

Unit 2 has experienced a number of silent half scrams due to over voltage conditions that tripped the EPAs while the alternate power supply was in service. The inspectors assessed NMPNS's problem identification threshold, cause analyses, extent of condition reviews, operability determinations, and the prioritization and timeliness of corrective actions to determine whether NMPNS was appropriately identifying and correcting problems associated with this issue.

b. Assessment and Observations No findings of significance were identified. The inspectors determined that NMPNS properly implemented their corrective action process regarding the initial discovery of the above issues. The CR packages were complete and included cause evaluations, operability determinations, extent of condition reviews, corrective actions completed, and planned corrective actions. Corrective actions addressed immediate operational concerns, and plant procedures provided directions for resetting the EPAs and clearing the half scrams.

However, the inspectors noted that these events have occurred over the life of the plant with the most recent events occurring in September 2007 and June 2008. Following the 2007 event, changes were made to the operating procedure for the AC power distribution system and a proposed plant modification to replace the existing transformers in the alternate supply with voltage regulating transformers was presented to the plant technical review board. Additional licensee reviews and approvals remain before the modification is fully approved and scheduled for implementation.

The inspectors also noted that, although the operating procedure improvements should reduce the likelihood of an EPA trip when aligned to the alternate power supply, those changes have not eliminated the vulnerability as indicated by the occurrence of the subsequent 2008 event. The inspectors determined that long term corrective actions such as the implementation of the proposed modification to add the regulating transformers was appropriate to resolve the issue and further reduce the potential for inadvertent plant scrams.

.3 Annual Sample - Review of Corrective Actions for Plugging of Small Bore Piping in Raw

Water Applications

a. Inspection Scope

In May 2008, Unit 1 experienced reduced seal water flow to both SW system pumps. This resulted in reduced SW system supply pressure due to air in-leakage through the operating pump's seal. The air intrusion was stopped by applying seal water from an external source and normal SW supply pressure was restored. Although the plant was able to operate at full power throughout this event, NMPNS recognized that, in the worst case, the condition could have resulted in a scram with complications. The issue was entered into the CAP as CR 2008-4256, through which a category 1 root cause analysis was performed.

The cause of the degraded seal water flow was that the small bore (3/4-inch diameter)carbon steel piping in the system was extensively fouled with sand/silt, corrosion products, and other debris. As part of the long term corrective actions, the small bore piping in the seal water system was replaced with stainless steel piping.

In light of the generic implications of this event, the inspectors examined NMPNS's actions to address small bore piping degradation in other raw water applications.

b. Assessment and Observations No findings of significance were identified. Several earlier CRs have documented flow restriction issues, primarily due to corrosion and silting, that Unit 1 has experienced with small bore piping in raw water systems. As a result of a 2001 adverse trend CR, NMPNS contracted to have a study performed to evaluate options for addressing raw water piping degradation at Unit 1. The study was completed in 2004 and recommended replacement of the small bore piping with upgraded materials, and installation of isolation valves to facilitate periodic cleaning and flushing of the piping. NMPNS also discussed the issue with other licensees and found that several were performing no planned replacements of small bore SW piping. NMPNS subsequently concluded that they would continue to repair/replace small bore raw water piping only on an as-needed basis.

There is currently no regularly scheduled preventive maintenance performed on the small bore piping in the SW system. Procedure NMPNS-SBI-001, "Small Bore Piping Corrosion Monitoring Program," Revision 02, specifies periodic ultrasonic examinations of emergency SW piping at Unit 1, and closed loop cooling system piping at both units; however, it does not include small bore SW piping in either unit. Procedure GAP-HSC-02, "System Aging Inspection and Cleanliness Controls," Revision 18, has steps to visually inspect Fluid systems for evidence of corrosion and fouling whenever the system is open for maintenance. This type of inspection has value, but is of limited scope, as it does not address small bore piping on a planned and systematic basis.

The lack of preventive/predictive maintenance on the SW system small bore piping, combined with the current practice of repairing/replacing the piping on an as needed basis, increases the potential for equipment malfunctions that could affect plant operations.

Subsequent to the May 2008 Unit 1 SW event, CR 2008-5126 was written to address small bore piping issues. It has a corrective action to validate the assumptions/conclusions in the 2004 report and to develop a plan for potential solutions to the issues with Unit 1 small bore piping exposed to raw water. As of this inspection, development of this plan was in its initial stages.

The inspectors concluded that NMPNS's response to the May 2008 Unit 1 SW seal water system failure, to replace the small bore carbon steel piping with stainless steel piping, was prompt and effective. However, the inspectors concluded that NMPNS has not acted aggressively to globally address degradation of small bore piping in raw water applications.

This observation does not constitute a violation of NRC requirements in that all associated systems have remained operable .

.4 (Closed) URI 05000410/2008005-02, Qualification of HPCS Pump Power Cables for

Submergence

a. Inspection Scope

In the fourth quarter of 2008, the inspectors examined potential degradation of power cables for the Unit 2 high pressure core spray (HPCS) system pump due to periodic submergence in water. The inspectors opened an unresolved item (URI) for this issue pending NMPNS's assembly of information concerning the basis for qualification of these cables for submerged conditions. This inspection was conducted to evaluate that information.

b. Findings

Introduction.

An NRC-identified Green NCV of 10 CFR Part 50, Appendix S, Criterion III, "Design Control," was identified, in that NMPNS failed to maintain the Unit 2 HPCS pump power cables in an environment for which they were designed. Although NMPNS had indications that these cables were periodically submerged in water, they could not demonstrate that the cables were designed for submerged conditions.

Description.

Condition Report (CR) 2007-1977 described a condition that occurred on April 1,2007, where water had leaked through the HPCS pump power cable penetrations into both the control and reactor buildings. This indicated that some, if not all, of the underground cable run was submerged in water. The inspectors reviewed several other CRs that documented similar occurrences of water leakage through these penetrations.

This indicated that the HPCS pump power cables were periodically being subjected to submergence in water.

NRC Generic Letter (GL) 2007-01, "Inaccessible or Underground Power Cable Failures That Disable Accident Mitigation Systems or Cause Plant Transients," informed licensees of power cable failures due to moisture-induced degradation. The GL discussed that periodic draining of the area around power cables may decrease the rate of cable insulation degradation, but would not prevent cable failures. In addition, the GL discussed that some licensees have detected cable degradation prior to failure through techniques for measuring and trending the condition of cable insulation.

NMPNS had a program to dewater the underground HPCS cable run every six months, and also monitored the condition of the power cable insulation through periodic HPCS pump motor insulation testing. NMPNS did not consider that additional action (such as more frequent dewatering of the cable run and increased cable insulation monitoring) was necessary because the HPCS power cables had been procured to be suitable for use in submerged applications.

In response to the URI, NMPNS provided the inspectors procurement, design, test. and evaluation documents for the HPCS pump power cables. Based on review of this additional information, the inspectors, assisted by the Electrical Engineering Branch of the NRC Office of Nuclear Reactor Regulation, determined that NMPNS had not demonstrated that the subject safety-related cables were qualified for submerged conditions for the life of the plant. In response to this conclusion, NMPNS entered the issue into the CAP as CR 2009-2901. As immediate corrective action, NMPNS dewatered and inspected the HPCS cable run, and changed the frequency of dewatering to monthly. Based on the inspection results, along with the cable design specifications and most recent test results, NMPNS concluded that the HPCS pump power cables would remain operable while they conduct a design change evaluation to examine methods to reduce cable exposure to submerged conditions.

Analysis.

The inspectors determined that NMPNS's failure to ensure that the HPCS pump power cables were maintained in an environment for which they were designed was a performance deficiency. The finding was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. The finding affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the significance of this finding using Inspection Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings." The finding was of very low safety significance because it was a qualification deficiency that did not result in loss of operability. The finding had a cross-cutting aspect in the area of problem identification and resolution, operating experience, because NMPNS did not use operating experience, such as GL 2007-01, to evaluate possible adverse effects of periodic submergence of the HPCS pump power cables (P.2.a per IMC 0305).

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that measures shall be established to ensure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, since April 1, 2007, NMPNS did not maintain the Unit 2 HPCS pump power cables in an environment for which they were designed. Specifically, NMPNS had indication that the HPCS pump power cables were periodically submerged, but did not take action to preclude the HPCS pump power cables from being submerged.

However, because of the very low safety significance and because the issue was entered into the CAP as CR 2009-2901, this violation is being treated as an NCV consistent with the NRC Enforcement Policy. (NCV 05000410/2009004-01, Unqualified HPCS Pump Power Cables Used in Submerged Conditions)40A5 Other Activities

.1 (Closed) VIO 05000220/2009003-02, Operator Failure to Obtain Senior Reactor Operator

Permission Prior to Changing Reactor Power (92702)

This violation (VIO) identified that on January 5,2008, contrary to TS required procedures, a reactor operator (RO) deliberately manipulated controls at Unit 1 to increase power without the approval or direction of a senior reactor operator (SRO); and the chief reactor operator (CRO) and RO manipulated the controls to decrease power without the approval or direction of an SRO when power exceeded the megawatt-thermal license limit; and, the CRO deliberately failed to immediately report the overpower and down power events to Operations management. This violation was documented in a March 16,2009, NRC letter to NMPNS. In an April 15, 2009, letter to the NRC, NMNPS outlined the reasons why the violation occurred, and corrective actions implemented in response to the January 5, 2008, overpower event. NMNPS determined that the event occurred because of two reasons:

(1) Operations management did not ensure that high standards of performance were being implemented on shift, which resulted in a flawed mental model associated with compliance with standards; and

(2) less than clear standards, expectations, and practices existed for maintaining power at or below the licensed thermal power limit. To correct these performance deficiencies, several corrective actions were implemented including conducting a stand down with operations management to share lessons learned, briefing each operating crew on the event, and developing guidelines to ensure power is maintained at or below rated core thermal power. New expectations for the RO at the controls were established through the Operations Night Orders, which reiterated the requirement to obtain approval of the control room SRO prior to performing reactivity manipulations. Additionally, a case study was developed and presented to operations and training department personnel that highlighted how erosion of standards associated with command and control and reactivity management led to the event. Finally, disciplinary action was taken against the two ROs who were directly involved in the event.

The inspectors reviewed the corrective actions outlined in the April 15, 2009, NMPNS letter to the NRC, and the corrective actions implemented as a result of a root cause analysis (CR 2008-0162) that was completed as a result of this event. The root cause analysis determined that a contributing cause of the event was that Operations management failed to minimize and manage an increasing administrative burden on crews to ensure there where no adverse impacts on existing fundamental roles and responsibilities of operating crews. Specifically, during the January 2008 event. the control room SROs were engaged in administrative duties such as preparing a procedure change and overseeing plant testing activities. As a result, the SROs were not able to provide proper oversight of plant activities and failed to identify the power manipulations by the ROs. This increased administrative workload occurred because of planned and unplanned staffing reductions in the operations support area. To address these contributory causes, staffing levels were increased in the operations department for Units 1 and 2. Further, procedures at Units 1 and 2 for power maintenance and control were strengthened, and management expectations regarding command and control and reactivity manipulations were reinforced through briefings and training sessions.

The inspectors concluded that the root cause analysis was thorough and complete.

Additionally, corrective actions taken were appropriate and timely. This violation is closed.

.2 Temporary Instruction (Til 2515/173. Review of the Implementation of the Industry Ground

Water Protection Voluntary Initiative

a. Inspection Scope

On August 24-28, 2009, the inspectors assessed the licensee's ground water protection program to determine whether the licensee had implemented the voluntary industry Ground Water Protection Initiative (GPI). The GPI was unanimously approved by a formal vote of the NEI member utility chief nuclear officers, which established the industry's commitment to implement the initiative. The GPI identifies the actions the industry deems necessary for implementation of a timely and effective ground water protection program.

The inspectors verified that the following objectives for the GPI were contained in the licensee's program:

1.1 Site Hydrology and Geology 1.2 Site Risk Management 1.3 On-Site Ground Water Monitoring 1.4 Remediation Process 1.5 Record Keeping 2.1 Stakeholder Briefing 2.2 Voluntary Communication 2.3 Thirty-Day Reports 2.4 Annual Reporting 3.1 Perform a Self-Assessment 3.2 Review the Program Under the Auspices of NEI The inspectors determined that all of the above referenced attributes were contained in the Nine Mile Point Radiological Ground Water Protection Program, with the exception of objective 3.2. Specifically, objective 3.2.a requires the performance of an independent initial review within one year of the performance of the initial self-assessment performed for objective 3.1.a. The self-assessment was performed in 2006, and while an initial review was performed in 2007, the licensee has subsequently questioned whether the initial review was independent. As a result, the licensee is undergoing an additional initial review, by personnel from outside the company, which was still in progress at the end of the inspection.

b. Findings

No findings of significance were identified .

.3 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with NMPNS's security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

b. Findings

No findings of significance were identified.

40A6 Meetings

.1 Exit Meeting

The inspectors presented the inspection results to Mr. Sam Belcher and other members of licensee management at the conclusion of the inspection on October 9,2009. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

S. Belcher, Vice President

J. Yoe, Acting Plant General Manager

T. Lynch, Plant General Manager

W. Byrne, Manager, Nuclear Safety and Security

J. Kaminski, Director, Emergency Preparedness

J. Krakuszeski, Manager, Operations

F. Payne, Unit 1 General Supervisor Operations

H. Strahley, Unit 2 General Supervisor Operations

T. Syrell, Director, Licensing

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None.

Opened and Closed

05000410/2009004-01 NCV Unqualified HPCS Pump Power Cables Used in Submerged Conditions (Section 40A2)

Closed

05000410/2008005-02 URI Qualification of HPCS Power Cables for Submergence (Section 40A2)

05000220/2009003-02 VIO Operator Failure to Obtain Senior Reactor Operator Permission Prior to Changing Reactor Power (Section 40A5)

Discussed

None.