IR 05000220/2010003

IR 05000220-10-003, 05000410-10-003, on 04/01/2010 - 06/30/2010, Nine Mile Point Nuclear Station, Units 1 and 2, Refueling and Other Outage Activities

ML102150109
Person / Time
Site:	Nine Mile Point
Issue date:	08/03/2010
From:	Glenn Dentel Reactor Projects Branch 1
To:	Belcher S Nine Mile Point
References
IR-10-003
Download: ML102150109 (35)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 August 3, 2010 Mr. Sam Belcher Vice President Nine Mile Point Nine Mile Point Nuclear Station, LLC P.O. Box 63 Lycoming, NY 13093 SUBJECT: NINE MILE POINT NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000220/2010003 AND 0500041012010003

Dear Mr. Belcher:

On June 30, 2010, 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 July 23,2010, 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 self-revealing 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 VLA1 of the NRC Enforcement Policy. If you .contest the NCV noted in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, AnN.: 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, jf you disagree with the cross-cutting aspect assigned to the 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. 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 htto:flwww.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room}.

Sincerely, IRAJ Glenn T. Dentel, Chief Projects Branch 1 Division of Reactor Projects DISTRIBUTION: S. Sloan, DRP M. Dapas, DRA (R10RAMAIL RESOURCE) K. Kolaczyk, DRP, SRI D. Lew, DRP (R1DRPMAIL RESOURCE) D. Dempsey, DRP, RI J. Clifford. DRP (R1DRPMAIL RESOURCE) K. Kolek, DRP, AA D. Roberts, DRS (R1DRSMaii Resource) D. Bearde, DRS P. Wilson, DRS (R1DRSMaii Resource) RidsNrrPMNineMilePointResource L. Trocine, RI OEDO RidsNrrDorlLpl1-1 Resource G. Dentel, DRP ROPReportsResource@nrc.gov N. Perry, DRP J. Hawkins, DRP SUNSI Review Complete: NP (Reviewer's Initials) ML102150109 DOCUMENT NAME: G:\DRP\BRANCH1\NINE MILE POINnREPORTS\2009 - 2010 INSPECT[ON REPORTS\IR 2010 003\(DRAFT) IR 2010*003.DOC -

After declaring this document "An Official Agency Record" it will be released to the Public.

To receive acopy of this document, indicate in the box: *C* =Copy without attachment/enclosure 'E' =Copy wilh allachmenVenclosure *N' = No copy OFF1CE RfJDRP I Ihp RflDRP I RIIDRP I NAME EKnutson/]h per phone NPerry/np GDentel/gd with EK DATE P7130/10 07/29f10 07130110 OFFICIAL RECORD COPY

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No.: 50-220,50-410 License No.: DPR-63, NPF-69 Report No.: 05000220/2010003; 05000410/2010003 Licensee: Nine Mile Point Nuclear Station, LLC (NMPNS)

Facility: Nine Mile Point, Units 1 and 2 Location: Oswego, NY Dates: April 1 through June 30, 2010 Inspectors: E. Knutson, Senior Resident Inspector D. Dempsey, Resident Inspector N. Perry, Senior Project Engineer J. Furia, Senior Health PhysiCist E. Gray, Senior Reactor Inspector J. Krafty, Resident Inspector B. Haagensen, Resident Inspector S. Sloan, Project Engineer D. Molteni, Operations Engineer Approved By: Glenn T. Dentel, Chief Projects Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000220/2010003,05000410/2010003; 04/01/2010 - 06/30/2010; Nine Mile Point Nuclear

Station, Units 1 and 2; Refueling and Other Outage Activities.

The report covered a three-month period of inspection by resident inspectors and announced inspections 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 aspects for the findings were determined using IMC 0310, "Components Within the Cross-Cutting Areas." 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.

A self-revealing finding of very low safety significance associated with a non-cited violation (NCV) of Technical Specification (TS) 5.4, "Procedures," was identified when Nine Mile Point Nuclear Station (NMPNS) Unit 2 operators used an inadequate procedure for reactor cavity drain down, which resulted in water being drained from the reactor pressure vessel (RPV) to a level that was significantly lower than had been planned. As a result, the steam dryer was partially uncovered, which produced elevated radiation levels on the refueling floor. As immediate corrective action, the control room operators took actions to raise water level back to the RPV flange. The event was entered into the corrective action program as condition report (CR) 2010-4408.

The finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was evaluated in accordance with Inspection Manual Chapter (IMC) 0609, Appendix G, "Shutdown Operations Significance Determination Process." The change in core damage frequency

(.6CDF) was determined to be of very low safety significance because of the multiple methods to inject water into the vessel and the time available to align these systems. The finding had a cross-cutting aspect in the area of human performance, resources, because NMPNS did not ensure that the RPV drain down procedure was adequate to assure nuclear safety (H.2.c per IMC 0310). (Section 1R20) .

Other Findings

None.

REPORT DETAILS

Summary of Plant Status

Nine Mile Point Unit 1 operated throughout the inspection period at full rated thermal power (RTP), with the exception of two brief power reductions to support planned maintenance, testing, and control rod pattem adjustments.

Nine Mile Point Unit 2 began the inspection period at approximately 99 percent RTP, in coast down {gradual power reduction due to fuel depletion} to refueling outage 12, which began on April 2. On May 2, operators commenced plant startup and the generator was paralleled to the grid the following day. Full RTP was achieved on May 6. On May 14, power was reduced to 95 percent for a control rod pattem adjustment and was restored to full RTP the following day. On June 12, power was reduced to 55 percent to place the 'A' reactor feedwater pump in service for functional testing of modifications that were performed during the refueling outage, and to perform a control rod sequence exchange. 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 Readiness of Offsite and Onsile AC Power Systems (One sample)

a. Inspection Scope

the inspectors verified that plant features and procedures for operation, and continued availability of offsite and onsite alternating current (AC) power systems for Unit 1 and Unit 2 during adverse weather were appropriate. The inspectors reviewed Operations Administrative Procedure S-ODP~OPS-0112, "Off-Site Power Operations and Interface,"

to ensure that appropriate information is exchanged between NMPNS and the transmission system operator when issues arise that could impact the offsite power system. The inspectors also verified that NMPNS procedures address measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite AC power system prior to and during adverse weather conditions.

b. Findings

No findings of Significance were identified.

.2 Readiness for Seasonal Extreme Weather Conditions (Two samples)

a. Inspection Scope

The inspectors verified the seasonal readiness for Unit 1 and Unit 2 in accordance with NMPNS procedure NAI-PSH-11, "Seasonal Readiness Program," Revision 06. The inspectors reviewed and verified completion of the operations department hot weather preparation checklists contained in procedures N1-0P-64, Revision 00200, and N2-0P 102, Revision 00800, "Meteorological Monitoring," for Units 1 and 2. respectively. The inspectors reviewed the procedurallimi1s and actions associated with elevated lake temperature and walked down selected areas of the plants to assess the effectiveness of the ventilation systems. The inspectors also reviewed the updated final safety analysis reports (UFSARs) to ensure that required systems that can be affected by hot weather were addressed by the procedures. In addition, the inspectors performed partial system walkdowns of the following systems that could be susceptible to, or exacerbate, the effects of hot weather:

• Unit 1 service water system;

• Unit 1 control room chillers;

• Unit 2 control building chilled water system; and

• Unit 2 turbine building chilled water (lithium bromide) system.

b. Findings

No findings of significance were identified .

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

a. Inspection Scope

The inspectors reviewed the UFSARs for Units 1 and 2, and the Unit 2 individual plant examination, concerning external flooding events at the site. The inspection included a walkdown of accessible areas of the site 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 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 emergency diesel generator (EDG) 102 due to increased risk significance while EDG 103 was inoperable during maintenance;

• Unit 1 core spray systems 121 and 122 due to increased risk significance while core spray system 112 was inoperable during maintenance;

• Unit 2 Division 2 EDG while the Division 1 EDG was inoperable for major maintenance during the refueling outage; and

• Unit 2 reactor core isolation cooling (RCIC) system due to its being a risk-significant single train system, as well as due to maintenance that was performed during the refueling outage.

b.

findings No findings of Significance were identified.

1R05 Fire Protection

.1 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," Unit 2 UFSAR Appendix 9B, *"Safe Shutdown Evaluation," and the applicable pre-fire plans.

The areas inspected included:

• Unit 1 reactor building (RB) 261 foot elevation;

• Unit 1 core spray 11 comer room, RB 198, 218, and 237 foot elevations;

• Unit 1 auxiliary control room, turbine building (TB) 261 foot elevation;

• Unit 2 steam tunnel, RB 240 foot elevation;

• Unit 2 condenser bay, TB 250 and 277 foot elevations; and

• Unit 2 feedwater heater bays, turbine building 250 and 277 foot elevations.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities (71111.08 - One sample)

a. Inspection Scope

A sample of nondestructive examination (NDE) activities was inspected during the Unit 2 refueling outage. This included a review of ultrasonic testing (UT) procedures for both manual performance demonstration initiative (POI) UT and manual phased array UT techniques, and the automated computer based phased array UT system for 14 of the dissimilar metal Class 1 welds. Included were the nozzle to safe end dissimilar metal N2, N4, and N6 welds. These procedural reviews inCluded interviews with UT technicians qualified by the POI process to verify their preparation to apply the procedural parameters for the examinations. The inspectors verified that previously identified embedded indications were analyzed to verify the acceptability of their condition and for continued use. The inspectors reviewed the NDE qualifications, including Electric Power Research Institute (EPRI) POI certifications, for the technicians responsible for doing the UT examinations, data collection. and review and interpretation of the inspection results.

The preparations, parameters, and procedure for ultrasonic examination of the nozzle inner radius and reactor pressure vessel (RPV) shell to N2. N4 and N9 nozzle welds were reviewed. The inspectors interviewed the UT technicians applying this equipment and observed the specialized examination contact wedges to confirm the adequacy of procedural and training preparation for the examinations.

The inspectors also observed the calibration technique and manual UT examination of the six inch diameter pipe*to-pipe weld 2ICS-57~07-FW412, done per the POI UT procedure, PDI-UT-1, "PDI Generic Procedure for the Ultrasonic Examination of Ferritic Pipe Welds, of NDEP-UT-6.23, Ultrasonic Examination of Ferritic Piping Welds,"

Revision 01000. The controlling work package and the completed UT data sheet were reviewed.

The radiographs for welds FW001 and FW006 for C90698141, 2RHS-004-298-2, Plug 4A, welded to the requirements of the American Society of Mechanical Engineers (ASME) Code Section III for Class 2 piping, were reviewed against the ASME Code requirements and the radiographic procedure NOE-RT-1, "Radiographic Examination Testing Procedure ASME Section I, III, V, VIII,IX," Revision O.

A sample of in-vessel visual inspection (/WI) video in-process examination, and IWI procedure and records for the core shroud, jet pump components, core spray components, top guide grid beams, and the steam dryer, were reviewed.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Regualification Program

.1 Ouarterly Review (71111.110 - Two samples)

a.

Insl2ectlon 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 June 15, 2010. the inspectors observed Unit 1 LORT to assess operator and instructor performance during a scenario involving a control rod out drift, a reactor recirculation pump (RRP) motor-generator trip, spurious opening of an electromatic relief valve, a small break loss of coolant accident, and loss of high pressure injection due to failure ofpower board 12 to transfer to offsite power following a main turbine trip. The inspectors evaluated the performance of risk-significant operator actions including the use of special operating procedures (SOPs) and emergency operating procedures (EOPs).

• On June 15,2010, the inspectors observed Unit 2 LORT to assess operator and instructor performance during a scenario involving failure of the in-service electro hydraulic control system pressure regulator, loss of a reactor feedwater pump, a reactor coolant system leak inside containment that led to a manual reactor scram and subsequent automatic emergency core cooling system (ECCS) initiation, failure of the Division 1 electrical system, and failure of the high pressure core spray and RCIC systems. 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 (71111.120 - Three sample)

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 Title 10, Code of Federal Regulations (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 control rod drive system;

• Unit 2 fire detection and suppression system; and

• Unit 2 standby gas treatment system.

b. Findings

No findings of significance were identified.

1R13 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 May 24, that included core spray system 111 and 121 quarterly surveillances, emergency cooling system 12 high steam flow instrument surveillance, EDG 102 monthly surveillance, emergent maintenance to troubleshoot a failure of reactor feedwater pump 13 flow control valve controllers to swap on demand, and installation of a temporary modification for torus*to*drywell vacuum relief valve 68-04 to correct a problem with its position indication and alarm instrumentation.

• Week of May 31, that included a power reduction to 90 percent to remove RRP 13 from service for maintenance on its associated motor-generator, to perform a control rod pattern adjustment, insertion of control rod 30-11 for maintenance on its associated hydraulic control unit, liquid poison system monthly surveillances, reactor building unit cooler maintenance that required temporary cooling to be supplied to the west instrument room and shutdown cooling pump room, and emergent maintenance to correct high oil temperature in the main transformer.

• Week of June 21, that included calibration of the average power range monitor (APRM) system using the traversing in-core probe system, reactor protection system (RPS) motor-generator 131 protective relay testing, containment spray raw water inter-tie check valve quarterly surveillance, RPS 11 reactor recirculation flow loop and flow converter calibrations, vital station battery charger 161A maintenance, and a one day outage of 115 kilovolt (kV) offsite supply line 4 due to offsite maintenance.

• Week of June 7, that included Division 2 EDG monthly surveillance, calibration of the APRM system using the traversing in-core probe system, a power reduction to 55 percent for a control rod sequence exchange and functional testing of the 'A' reactor feedwater pump and minimum flow valve following modification during the refueling outage, and emergent maintenance to troubleshoot failure of the 'B' sixth point feedwater heater level control valve that resulted in a trip of the 'B' heater drain pump.

• Week of June 14, that included main steam isolation valve (MSIV) partial stroke testing, RCIC system quarterly surveillance to verify proper operation of the trip throttle valve, maintenance on the Division 2 EDG, APRM channel 2 cycle surveillance, and emergent maintenance to troubleshoot failure of the RPS input from MSIV 7C to reset following partial stroke testing, and to replace a broken shear pin on the 'C' service water pump discharge strainer.

• Week of June 21, that included maintenance on the Division 1 service water to circulating water system makeup isolation valves, Division 1 EDG monthly surveillance, Division 1 control room envelope filtration system quarterly surveillance, Division 1 standby gas treatment system filter replacements, main turbine overspeed trip testing, a one day maintenance outage for the low pressure core spray system including quarterly surveillance, and emergent maintenance to replace the RPS channel'B2' 2-out-of-4 logic module following a failure that caused an RPS 'B' half scram, and to troubleshoot a failed bearing in service water pump

'A.'

b. Findings

No findings of significance were identified.

'I R15 Operability Evaluations (71111.15 Six samples)

H a. . Inspection Scope The inspectors evaluated the acceptability of operability evaluations, the use and control of compensatory measures, and compliance with technical specifications (TS). 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' reviews 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:

• Condition reports (CRs) 2010-3060 and 2010-3094 concerning a potential operability concern for the Unit 2 Division 1 EDG following a voltage regulation problem that had occurred with the Division 2 EDG during surveillance testing;

• CR 2010-0196 concerning Unit 2 intermediate range monitor 'F' operability at the beginning of the refueling outage, in light of its having produced multiple spurious RPS trip signals during the previous reactor shutdown;

• CR 2010-4595 concerning the effect of post-refueling outage voids in the low pressure core spray system on system operability;

• CR 2010-4875 concerning Unit 2 RCIC system operability with a failure of the trip throttle valve trip feature;

• CR 2010-5447 and engineering change package (ECP) 10-000444 concerning the operability of Unit 1 torus-to-drywell vacuum relief valve 68-04 with an input signal from the valve position indication circuit being provided to its associated annunciator, a change that was performed to satisfy TS alarm and indication requirements; and

• CR 2010-6273, Unit 2 MSIV 7C operability after a failure of its input to the RPS to reset during partial valve stroke testing.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

.1 Permanent Modifications (One sample)

a. Inspection Scope

The inspectors reviewed Unit 2 permanent plant modification ECP-09-000540, "Standby Liquid Control System Upgrade." The purpose of this change was to increase the pressure rating of the system and increase the capacity of the pumps to provide additional safety margin for the system. The inspectors interviewed the system engineer, reviewed the applicable design documentation and 10 CFR Part 50.59 screening against system design basis information, verified that post-installation tests were adequate, and verified that NMPNS controlled the modification in accordance with station procedures.

b. Findings

No findings of significance were identified.

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

a.

Inspection ScoRe 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 basisand/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 1r Work Orders (WOs) C90658539 and C90658565 to perform core spray and core spray tapping pump supply breaker maintenance per N1-EPM-GEN-150, "4.16KV Breaker Inspection PM [preventive maintenance]," Revision 01100. The PMT was to demonstrate proper breaker operation during the performance of N1 ST-Q1C, "CS [core spray] 112 Pump and Valve Operability Test," Revision 00600.

• Unit 1, WO C90863853 to perform corrective maintenance on instrument air compressor 13. The PMT was to demonstrate normal operation in accordance with N1-0P-20, "Service Instrument and Breathing Air Systems," ReVision 02900.

• Unit 2, Division 2 EDG overspeed trip test per N2-0SP-EGS-R001, "Diesel Generator Inspection Division 1 and 2," Revision 01300, performed as PMT following major engine maintenance during the refueling outage.

• Unit 2, WO C90846886 to repair containment isolation valve 2RDS*AOV130. The PMT was a local leak rate test performed in accordance with N2-ISP-LRT-R@072, "Type 'C' Containment Isolation Valve Leak Rate Test 2RDS*AOV123, 2RDS*AOV124, 2RDS*AOV130, 2RDS*AOV131," Revision 04.

• Unit 2, WO C081245100 to readjust the torque switch on 2RHS*MOV24A. The PMT was a local leak rate test performed in accordance with N2-ISP-LRT-R@073, "Type

'C' Containment Isolation Valve Leak Rate Test 2RHS*MOV16A, 2RHS*MOV24A,"

Revision 07.

• Unit 2. N2-0SP-RPV-@003, "Reactor Pressure Vessel and All Class I Systems Leakage Test with the RPV Solid," Revision 00601, performed as PMT for reactor vessel reassembly and various other component maintenance performed during the refueling outage.

• Unit 2, N2-0SP-RMC-@001, "Control Rod Drive Scram Insertion Time Testing,"

Revision 01603, performed as PMT for control rod drive unit and control rod blade replacements that were performed during the refueling outage.

• Unit 2, WO C90669453 to increase the capacity of the Divison 1 standby liquid control pump per ECP-09-000540, "Increase SLS [standby liquid control] System Design Pressure and Upgrade Capacity of SLS Pumps." The PMT was to test the pump in accordance with N2-0SP-SLS-Q001, "Standby Liquid Control Pump, Check Valve, Relief Valve Operability Test and ASME XI Pressure Test," Revision 01100.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20 - One sample)

a. Inspection Scope

The inspectors observed and/or reviewed the following Unit 2 refueling outage activities to verify that operability requirements were met and that risk, industry experience, and previous site-specific problems were considered.

• Prior to the refueling outage, the inspectors met with the fatigue program administrators and reviewed how workers' hours would be managed and how the program would be used to monitor fatigue during the outage for both the unit in the outage and the operating unit During the refueling outage, the inspectors discussed, with workers and supervisors, how fatigue was being managed, to ensure that they were aware of their limits and responsibilities. The inspectors also met with the program administrators and discussed waiver requests, deviations, self declarations and fatigue assessments.

• The inspectors reviewed the outage schedule and procedures, and verified that TS required safety system availability was maintained and shutdown risk was minimized. The inspectors verified that, when speCified by NMPNS procedure NIP OUT*01, "Shutdown Safety," contingency plans existed for restoring key safety functions.

• The inspectors observed portions of the plant shutdown and cootdown, and verified that the TS cooldown rate limits were satisfied.

• Through plant tours, the inspectors verified that NMPNS maintained and adequately protected electrical power supplies to safety related equipment and that TS requirements were met.

• The inspectors verified proper alignment and operation of shutdown cooling and other 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 verified that requirements for refueling operations were met through refuel bridge observations, control room panel walkdowns, and discussions with Operations Department personnel.

• Before the drywell was closed from general access for startup, the inspectors performed an "as-left" walkdown to identify evidence of reactor coolant system (RCS) leakage and verify the condition of drywell coatings, structures, valves, piping, supports, and other equipment in areas where maintenance was completed. 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, and verified through plant walkdowns, control room observations, and surveillance test reviews that safety related equipment speCified for mode change was operable.

b. Findings

Introduction.

A self-revealing finding of very low safety significance (Green) associated with a non-cited violation (NCV) of TS 5.4, "Procedures," was identified on April 24, 2010, when Unit 2 operators used an inadequate procedure for reactor cavity drain down, which resulted in water being drained from the reactor vessel to a level that was significantly lower than had been planned. As a result, the steam dryer was partially uncovered. which produced elevated radiation levels on the refueling floor.

Description.

On April 24, 2010, operators prepared to drain the reactor refueling cavity in preparation for RPV reassembly. The drain down would be performed using procedure N2-PM-082, "RPV Flood Up I Drain Down," Revision 00200. The procedure was newly developed, and consisted of applicable information compiled from the various individual system operating procedures that had been used to perform cavity flood ups and drain downs during previous refueling outages. By this procedure, water is removed from the reactor cavity using the residual heat removal (RHR) shutdown cooling system to pump water to the suppression pool and the radioactive waste system, the spent fuel pool cooling system to pump water to the main condenser hotwell. and the main sleam line drains to drain water to the main condenser hotwell.

This combination of drain down paths results in rapid reactor cavity drain down and also facilitates the distribution of the water among the available storage tanks.

the initial water level in the reactor cavity was approximately 23 feet above the RPV flange, with a volume of approximately 525,000 gallons. The combined drain down rate through the four drain paths would be approximately 6500 gallons per minute, which would cause refueling cavity water level to decrease at a rate of approximately 3.6 inches per minute. Water level indication would be provided to the control room operators by the shutdown range reactor water level instrument, with an indicating range of 545 inches to 145 inches referenced to instrument level zero (18 inches above top of active fuel); by this indication, the RPV flange is at 364 inches. Also, an operator in communication with the control room would be stationed on the refueling floor to continuously monitor reactor cavity level.

Control room operators commenced refueling cavity drain down at 7:50 a.m., with a target water level of between the RPV flange and six inches below the flange. The operators planned to start reducing the drain down flow rate at a level of 400 inches, to support approaching and establishing this band in a controlled manner. N2-PM-082 did not provide specific values for either the final level band or the level a1 which throttling of the drain down flow should commence. Furthermore, the procedure did not integrate steps to secure the four drain down paths, such that they would be performed sequentially (highest to lowest flow rate) to provide graded control for establishing the desired level band.

Although N2-PM-082 required that an operator be stationed on the refuel floor to monitor refueling cavity level, it provided no further guidance. As a result. the operator was monitoring reactor cavity level via a closed circuit television (CCTV) system rather than by direct visual observation. The CCTV did not provide clear indication of the water's surface at all times. Additionally, the procedure provided no correlations between physical features in the reactor cavity and shutdown range level instrument indication. As a result. the local observer was ineffective as a backup means of water level indication.

As the reactor cavity drain down proceeded, the control room operators observed water level indication come on scale at 545 inches and lowering on the shutdown range water level instrument. However, the operators did not notice that the meter subsequently hung up at an indicated level of 410 inches (NMPNS suspects that this was due to a static charge on the meter), and so, continued to drain beyond the point that they had intended to begin reducing the drain down rate.

At 9:15 a.m., the refueling floor operator reported to the control room that reactor cavity water level was at the bottom of the fuel transfer canal. This corresponds to a level of 372 inches on the shutdown range level instrument, but this fact was not known by the control room operators; based on the indicated level of 410 inches, the drain down continued. Three minutes later, the control room operators observed the shutdown range level indication rapidly drop to 360 inches, or four inches below the RPV flange.

The operators immediately commenced securing the drain down. By the time that was completed, water level had decreased to 54 inches below the RPV flange, which partially uncovered the steam dryer. As a result, radiation levels at the reactor cavity handrail had increased from approximately 10 millirem per hour (10 mrem/hr) to approximately 300 mrem/hr. Radiation protection technicians had previously cleared personnel from around the refueling cavity, so the localized increase in radiation levels did not cause any unnecessary increase in personnel exposure.

As immediate corrective action, the control room operators took actions to raise water level back to the RPV flange. Although the procedure did not address recovery from this condition, it was done in a controlled manner to minimize the creation of airborne activity due to rewetting the exposed portions of the steam dryer. RPV level was stabilized at one inch below the flange at 10:25 a.m. No significant airborne activity was produced during the RPV refill and no personnel were contaminated. The excessive drain down event was entered into the corrective action program as CR 2010-4408.

AnalysiS. The inspectors determined that draining the RPV to 4.5 feet below the RPV flange, during an operation that was intended only to drain the cavity above the RPV, was a performance deficiency. Constellation Nuclear Generation Fleet Administrative Procedure CNG-PR-1.01-1 005, "Control of Constellation Nuclear Generation Technical Procedure Format and Conten!," Revision 00300, indicates that procedures are to be written with Jittle or no margin for interpretation. The procedure inadequacies that led to this reduced inventory condition could have challenged shutdown cooling and the emergency core COOling systems. The finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," the finding was evaluated in accordance with IMC 0609, Appendix G, "Shutdown Operations Significance Determination Process." From Checklist 8, "Boiling Water Reactor Cold Shutdown or Refueling Operation, Time to Boil Greater than Two Hours: Reactor Coolant System Level Less than 23 feet Above Top of Flange," the inspectors determined that a Phase 2 analysis was required because the finding was associated with a loss of reactor coolant system inventory. The following assumptions were made during the evaluation: 1) the auto initiation capability of low pressure coolant injection (LPCI) systems 'A' and 'C' was functional; 2) time to boil, had level 3 been reached, was greater than five hours; and 3)other systems available for injection included, as a minimum, control rod drive system

'8', service water, and fire water. The dominant core damage sequences were 1) LOI (loss of inventory) - AECCS (early automatic ECCS) - MINJ (manual low pressure injection -leak isolated), and 2) LOI- ISOL (isolation of the loss) - LCOOL (long term cooling). The resultant change in core damage frequency (LlCDF) was in the low E-7/year range, which is of very low safety significance (Green).

The condition was also evaluated for large early release frequency (LERF) in accordance with MC 0609 App H, "Containment Integrity Significance Determination Process." Applying Figure 5.2, since the finding belongs to TWL (the late time window, after refueling operations), POS3 (RPV water level equal to or greater than the minimum level required for movement Of irradiated fuel assemblies within the RPV), or greater than eight days of outage (which is the applicable condition in this case), the result equates to the ACDF for color of the finding. Specifically, there was no impact from LERF due to decay of iodine after such a long period Since shutdown.

The finding had a cross-cutting aspect in the area of human performance, resources, because NMPNS did not ensure that the RPV drain down procedure was adequate to assure nuclear safety (H.2.c per IMC 0310).

Enforcement.

TS 5.4, "Procedures," states, in part, "Written procedures shall be established, 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, Section g, "Procedures for Performing Maintenance," subsection d states, "Procedures that could be categorized either as maintenance or operating procedures should be developed for the following activities," one of which is, "Draining and Refilling the Reactor Vessel;" in addition, subsection a, states, in part, "Maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures ... appropriate to the circumstances."

Contrary to the above, on April 24. 2010, the procedure that NMPNS used to drain the Unit 2 reactor cavity, N2-PM-082, "RPV Flood Up I Drain Down," Revision 00200, was not appropriate to the circumstances, in that it did not provide adequate detail to ensure that water level would be positively controlled such that the RPV would not be drained below the flange. As a result, the reactor vessel was drained to a level 4.5 feet below the RPV flange, which caused the steam dryer to be partially uncovered and. in turn.

resulted in elevated radiation levels on the refueling floor. Because this violation was of very low safety significance and was entered into the corrective action program (CAP)as CR 2010-4408, this violation is being treated as an NCV, consistent with the NRC Enforcement Policy. (NCV 05000410/2010003-01

• Excessive Reactor Pressure Vessel Drain Down due to Inadequate Procedure)

1R22 Surveillance Testing (71111.22 - Seven samples)

a.

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

Revision 00801 ;

• N1-ST-Q1 B, "CS [core spray] 121 Pump, Valve. and SDC [shutdown cooling] Water Seal Check Valve Operability Test." Revision 01100;

• N2-ISP-RCS-R205B, "End-of-Cycle Recirculation Pump Trip Arc Suppression Response Time Test for Recirculation Pump Trip System 'B'," Revision 01;

• N2-0SP-MSS-CS001, "Main Steam Isolation Valve Operability Test," Revision 00501;

• N2-0SP-EGS-R004. "Operating Cycle Diesel Generator Simulated Loss of Offsite Power with ECCS Division I & II," Revision 00901, for the Division 1 EDG;

• N2-ESP-BYS-R685, "Division 11111111 Battery Modified Profile Test," Revision 00400, for the Division 2 battery; and

• N2-ISP-LRT-R@058, "Type "C" Containment Isolation Valve Leak Rate Test 2ICS*MOV156, 2ICS*MOV126. 2RHS*MOV104, 2ICS*V288," Revision 07. for ICS*MOV126.

This represented a total of seven inspection samples, of which three were Routine Surveillances, three were In-Service Testing, and one was a Containment Isolation Valve Surveillance as defined by Inspection Procedure 71111.22.

b. Findings

No findings of significance were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Radiological Hazard Assessment The inspectors determined if, since the last inspection, there have been changes to plant operations that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors verified NMPNS has assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last two radiological surveys from three to six selected plant areas. The inspectors verified that the thoroughness and frequency of the surveys was appropriate for the given radiological hazard.

The inspectors conducted walkdowns of the facility. including radioactive waste processing, storage, and handling areas, to evaluate material conditions and potential radiological conditions (radiological control area). protected area, controlled area, contaminated tool storage. or contaminated machine shops.

The inspectors selected three to five radiologically risk-significant work activities that involved exposure to radiation. The inspectors verified that appropriate pre-work surveys were performed which were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were properly identified, including the following:

• Identification of hot particles;

• The presence of alpha emitters:

• The potential for airborne radioactive materials, inCluding the potential presence of transuranics and/or other hard-to-detect radioactive materials;

• The hazards aSSOCiated with work activities that could suddenly and severely increase radiological conditions; and

• Severe radiation field dose gradients that can result in nonuniform exposures of the body_

The inspectors selected three to five air sample survey records and verified that samples were collected and counted in accordance with NMPNS procedures. The inspectors observed work in potential airborne areas, and verified that air samples were representative of the breathing air zone. The inspectors verified that NMPNS has a program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

Radiological Hazards Control and Work Coverage During tours of the facility and review of ongoing work selected in Section 2RS1 (above), the inspectors evaluated ambient radiological conditions. The inspectors verified that existing conditions were consistent with posted surveys, radiation work permits (RWPs). and worker briefings. as applicable.

During job performance observations, the inspectors verified the adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination controls. The inspectors evaluated NMPNS's means of using electronic personal dosimeters in high noise areas as high radiation area monitoring devices.

The inspectors verified that radiation monitoring devices were placed on the individual's body conSistent with the method that NMPNS was employing to monitor dose from external radiation sources. The inspectors verified that the dosimeter was placed in the location of highest expected dose or that NMPNS was properly employing an NRC~approved method of determining effective dose equivalent.

For high-radiation work areas with significant dose rate gradients (a factor of five or more), the inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel. The inspectors verified that NMPNS controls were adequate.

The inspectors reviewed three to five RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures. The inspectors evaluated airborne radioactive controls and monitoring, including potentials for significant airborne contamination. For these selected airborne radioactive material areas, the inspectors veri'fied barrier integrity and temporary high-efficiency particulate air ventilation system operation.

The inspectors examined NMPNS's physical and programmatic controls for highly activated or contaminated materials stored within spent fuel and other storage pools.

The inspectors verified that appropriate controls were in place to preclude inadvertent removal of these materials from the pool.

The inspectors conducted selective inspection of posting and physical controls for high radiation areas and very high radiation areas, to the extent necessary to verify conformance with the occupational performance indicator.

b. Findings

No findings of significance were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

Radiological Work Planning The inspectors obtained from NMPNS a list of work activities ranked by actual or estimated exposure that were in progress or that have been completed during the last outage, and select work activities of the highest exposure significance.

The inspectors reviewed the as low as reasonably achievable (ALARA) work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors determined that NMPNS had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.

The inspectors verified that NMPNS's planning identified appropriate dose mitigation features; considered, commensurate with the risk of the work activity, alternate mitigation features; and defined reasonable dose goals. The inspectors verified that NMPNS's ALARA assessment had taken into account decreased worker efficiency from use of respiratory protective devices and/or heat stress mitigation equipment. The inspectors determined that NMPNS's work planning considered the use of remote technologies as a means to reduce dose and the use of dose reduction inslghts from industry operating experience and plant-specific lessons learned. The inspectors verified the integration of ALARA requirements into work procedure and RWP documents.

The inspectors compared the results achieved with the intended dose established in NMPNS's ALARA planning for these work activities. 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 the reasons for any inconsistencies between intended and actual work activity doses. The inspectors focused on those work activities with planned or accrued exposure greater than five personyrem.

The inspectors determined that post-job reviews were conducted and that identified problems were entered into NMPNS's CAP.

b. Findings

,

\ .

No findings of significance were identified.

2RS7 Radiological Environmental Monitoring Program (71124.07 - One sample)

a. Inspection Scope

The inspectors reviewed the annual radiological environmental operating report, and the results of any licensee assessments since the last inspection, to verify that the radiological environmental monitoring program (REMP) was implemented in accordance with the plant TSs and the offslte dose calculation manual (ODeM). The inspectors reviewed the report for changes to the ODCM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring a~d measurement frequencies, land use census, interlaboratory comparison program, and analysis of data.

The inspectors reviewed the ODCM to identify locations of environmental monitoring stations.

The inspectors reviewed the UFSARs for information regarding the environmental monitoring program and meteorological monitoring instrumentation.

The inspectors reviewed the annual effluent release report and the 10 CFR Part 61, "Licensing Requirements for land Disposal of Radioactive Waste," report, to determine if NMPNS was sampling, as appropriate, for the predominant and dose-causing radionuclides likely to be released in effluents.

Site Inspection The inspectors walked down air sampling stations and thermoluminescent dosimeter (TlD) monitoring stations to determine whether they were located as described in the ODCM and to determine the equipment material condition.

For the air samplers and TlDs selected above, the inspectors reviewed the calibration and maintenance records to verify that they demonstrate adequate operability of these components. Additionally, the inspectors reviewed the calibration and maintenance records of composite water samplers. as available.

The inspectors verified that NMPNS had initiated sampling of other appropriate media upon loss of a required sampling station.

The inspectors observed the collection and preparation of environmental samples from different environmental media (e.g., ground and surface water, milk, vegetation, sediment, and soil), as available. The inspectors verified that environmental sampling was representative of the release pathways as specified in the ODCM and that sampling techniques were in accordance with procedures.

Based on direct observation and review of records, the inspectors verified that the meteorological instruments were operable, calibrated. and maintained in accordance with guidance contained in the UFSAR, NRC Regulatory Guide 1.23, "Meteorological Monitoring Programs for Nuclear Power Plants," and NMPNS procedures. The inspectors verified that the meteorological data readout and recording instruments in the control room and at the tower were operable.

The inspectors verified that missed and or anomalous environmental samples were identified and reported in the annual environmental monitoring report. The inspectors reviewed NMPNS's assessment of any positive sample results (i.e., licensed radioactive material detected above the lower limits of detection (LlDs>>. The inspectors reviewed the associated radioactive effluent release data that was the source of the released material.

The inspectors selected structures, systems, and components (SSCs) that involved or could reasonably involve licensed material for which there is a credible mechanism for licensed material to reach ground water, and verified that NMPNS had implemented a sampling and monitoring program sufficient to detect leakage from these SSCs to ground water.

The inspectors verified that records, as required by 10 CFR Part 50.75(g}, of leaks, spills, and remediation since the previous inspection were retained in a retrievable manner.

The inspectors reviewed any significant changes made by NMPNS to the ODCM as the result of changes to the land census, long-term meteorological conditions (3-year average). or modifications to the sampler stations since the last inspection. The inspectors reviewed technical justifications for any changed sampling locations. The inspectors verified that NMPNS performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases on the environment.

The inspectors verified that the appropriate detection sensitivities with respect to TS/ODCM were used for counting samples (Le., the samples meet the TS/ODCM required LLDs). The inspectors reviewed quality control charts for maintaining radiation measurement instrument status and actions taken for degrading detector performance.

The inspectors reviewed the results of NMPNS's interlaboratory comparison program to verify the adequacy of environmental sample analyses performed by NMPNS. The inspectors verified that the interlaboratory comparison test included the media/nuclide mix appropriate for the facility.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

40A1 Performance Indicator Verification (71151 - Four samples)

a. Inspection Scope

The inspectors sampled NMPNS submittals for the performance indicators (Pis) listed below. To verify the accuracy of the PI data reported during that period, the PI definition guidance contained in Nuclear Energy Institute (NEI) 99~02, "Regulatory Assessment Indicator Guideline," Revision 6, was used to verify the basis in reporting for each data element.

Cornerstone: Barrier Integrity

The inspectors reviewed operator logs, plant computer data, and daily sampling and surveillance procedure results to verify the accuracy of NMPNS's reported reactor coolant system (RCS) Pis from April 2009 to March 2010.

• Unit 1 RCS leak rate;

• Unit 1 RCS specific activity;

• Unit 2 RCS leak rate; and

• Unit 2 RCS specific activity.

b. Findings

No findings of significance were identified.

40A2 Problem Identification and Resolution (71152)

.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.

The extent of oversight of inservice inspection (lSI) and NDE activities including the topics of current lSI oversight and assessments and audits were reviewed. The inspectors reviewed a sample of CRs to confirm that identified problems were being documented for evaluation and proper resolution.

The inspectors verified that problems associated with the REMP were being identified by NMPNS at an appropriate threshold and were properly addressed for resolution in the licensee's CAP. The inspectors verified the appropriateness of the corrective actions for a selected sample of problems documented by NMPNS that involved the REMP.

b. Findings

No findings of significance were identified.

.2 Semi~AnnuaJ Review to Identify Trends (One sample)

a. Inspection Scope

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

the inspectors reviewed NMPNS's CAP and associated documents to identify trends that could indicate significant safety issues and/or low level trends before they become significant. The inspectors' review focused on repetitive equipment and corrective maintenance issues, and considered the results of the daily inspector CAP item screening. The review included issues documented outside of the normal CAP in system health reports. quality and performance assessment reports, and the unit specific significant issues lists. The inspectors' review considered the period January 2010 through June 2010.

b. Findings

No findings of significance were identified.

40A3 Follow-up of Events and Notices of Enforcement Discretion (71153)

.1 (Closed) LER 05000410/2010-001-00 and -01, Reactor Scram Due to Inadvertent

Actuation of the Redundant Reactivity Control System During Maintenance On January 7, 2010, Unit 2 scrammed from full RTP due to inadvertent actuation of the alternate rod insertion (ARI) function of the redundant reactivity control system (RRCS).

Prior to the scram, technicians were restoring an RHR system pressure detector following maintenance. The detector is connected to multiple other detectors through a common reference line, one of which is for the low reactor vessel water level input to the RRCS. The multiple detector configuration had not been identified during the work planning process, so the possible effects of the maintenance activity on plant operation had not been addressed. The operation to fill and vent the RHR detector perturbed the RRCS detector such that it sensed an invalid transient low reactor vessel water level condition, and thereby initiated the system. Similarly, the RCIC system received an invalid low reactor vessel level initiate signal and subsequently shut down when actual Jevel increased following the scram.

As discussed in revision 01 to this Licensee Event Report (LER), NMPNS determined that the root cause of this event was that Operations Management had not sufficiently monitored the adequacy of plant impact assessments during work planning. Corrective actions included additional training for Operations planning personnel and periodic management review meetings to reinforce standards and expectations in this area. The inspectors concluded that these corrective actions appropriately addressed the root cause of the event.

The events detailed in this LER were discussed in Section 40A3 of inspection report 05000410/2010002 and resulted in an NCV. The inspectors reviewed the original and revised LERs and no additional findings of significance were identified. This LER. and the revision, are closed.

40A6 Meetings

.1 Exit Meeting

The inspectors presented the inspection results to Mr. Sam Belcher and other members of NMPNS management at the conclusion of the inspection on July 23,2010. The inspectors asked NMPNS whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

NMPNS Personnel

S. Belcher, Vice President

T. Lynch. Plant General Manager

W. Byme, Manager, NUclear Safety and Security

J. Dean, Director Nuclear Oversight

R. Dean, Training Manager

S. Dhar, Design Engineering

J. Holton, Supervisor, Systems Engineering

J. Kaminski, Director, Emergency Preparedness

J. Krakuszeski, Manager. Operations

M. Kunzwiler, Security Supervisor and Fatigue Rule Program Coordinator

F. Payne, Unit 1 General Supervisor Operations

M. Shanbhag, LIcenSing Engineer

S. Sova, Radiation Protection Manager

H. Strahley. Unit 2 General Supervisor Operations

T. Syrell, Director, licensing

J. Vaughn, Operations Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None.

Opened and Closed

05000410/2010003-01 NCV Excessive Reactor Pressure Vessel Drain Down due to Inadequate Procedure (Section 1R20)

Closed

05000410/2010~001-00 and LER Reactor Scram Due to Inadvertent

05000410/2010-001-01 Actuation of the Redundant Reactivity Control System During Maintenance (Section 40A3)

Discussed

None.