IR 05000220/2008005

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IR 05000220-08-005, 05000410-08-005 on 10/01/08 - 12/31/08 for Nine Mile Point, Units 1 and 2, Maintenance Risk Assessments and Emergent Work Control
ML090270145
Person / Time
Site: Nine Mile Point  Constellation icon.png
Issue date: 01/27/2009
From: Glenn Dentel
Reactor Projects Branch 1
To: Polson K
Nine Mile Point
Dentel, G RGN-I/DRP/BR1/610-337-5233
References
IR-08-005
Download: ML090270145 (41)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ary 27, 2009

SUBJECT:

NINE MILE POINT NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000220/2008005 and 05000410/2008005

Dear Mr. Polson:

On December 31, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Nine Mile Point Nuclear Station, Units 1 and 2. The enclosed integrated inspection report documents the inspection results discussed on January 23, 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 Commissions 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) which was determined to involve a violation of NRC requirements. However, because of its very low safety significance and because it was entered into your corrective action program (CAP), the NRC is treating this violation as a non-cited violation (NCV) in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you contest the NCV noted in this report, you should provide a response with the basis for your denial, within 30 days of the date of this inspection report, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C.

20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-001; and the NRC 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 NRCs document system (ADAMS). ADAMS is accessible from the NRC Web Site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/ Original Signed By:

Glenn T. Dentel, Chief Projects Branch 1 Division of Reactor Projects Docket No.: 50-220, 50-410 License No.: DPR-63, NPF-69 Enclosure: Inspection Report 05000220/2008005 and 05000410/2008005 w/Attachment: Supplemental Information cc w/encl:

M. Wallace, Vice - Chairman, Constellation Energy H. Barron, President, CEO & Chief Nuclear Officer, Constellation Energy Nuclear Group C. Fleming, Esquire, Senior Counsel, Nuclear Generation, Constellation Energy Group, LLC M. Wetterhahn, Esquire, Winston & Strawn T. Syrell, Director, Licensing, Nine Mile Point Nuclear Station P. Tonko, President and CEO, New York State Energy Research and Development Authority J. Spath, Program Director, New York State Energy Research and Development Authority P. Eddy, New York State Department of Public Service C. Donaldson, Esquire, Assistant Attorney General, New York Department of Law Supervisor, Town of Scriba P. Church, Oswego County Administator T. Judson, Central NY Citizens Awareness Network D. Katz, Citizens Awareness Network G. Detter, Manager, Nuclear Safety and Security, Constellation Energy

SUMMARY OF FINDINGS

IR 05000220/2008005, 05000410/2008005; 10/01/08 - 12/31/08; Nine Mile Point Nuclear Station,

Units 1 and 2; Maintenance Risk Assessments and Emergent Work Control.

The report covered a three-month period of inspection by resident inspectors and regional specialist inspectors. One Green NCV was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC)0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

Green.

An NRC-identified Green non-cited violation (NCV) of 10 CFR 50, Appendix B,

Criterion XVI, "Corrective Action," was identified on November 8, 2008 in that Nine Mile Point Nuclear Station (NMPNS) did not take prompt action to verify that service water (SW) pump performance had not been adversely affected following the inadvertent introduction of a cleaning hose into the pump suction lines. This resulted in delayed identification of two inoperable Unit 2 SW pumps due to fouling of the impellers by foreign material that had been drawn into the pumps on November 4, 2008. As immediate corrective action, the affected pumps were disassembled and the pieces of cleaning hose were removed.

The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The finding was determined to be of very low safety significance in accordance with Inspection Manual Chapter (IMC) 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations," based on a Phase 2 analysis using the Nine Mile Point Unit 2 plant-specific Phase 2 pre-solved worksheets. The finding had a cross-cutting aspect in the area of human performance because NMPNS did not use conservative assumptions in decision making, in that they did not timely verify the assumption that the cleaning hose was fully retrieved and had not impacted operability of the service water pumps (H.1.b per IMC 0305). (Section 1R13)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Nine Mile Point Unit 1 began the inspection period at full rated thermal power (RTP). On October 10, power was reduced to 70 percent for power suppression testing to identify and suppress a leaking fuel bundle. This was completed on October 12 and power escalation was commenced, with full RTP being reached on October 13. On October 23, operators inserted a manual scram due to failure of the electronic pressure regulator (EPR) that caused a loss of reactor pressure control. Following repair, a reactor startup was performed on October 26 and full RTP was achieved on October 28. On November 1, power was reduced to 80 percent for a control rod pattern adjustment, and was restored to full RTP later that day. On December 20, power was reduced to 82 percent for a control rod pattern adjustment and turbine valve testing. 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 October 18, power was reduced to 67 percent for a control rod sequence exchange and single control rod scram time testing. Power was restored to full RTP the following day. On November 13, Unit 2 shut down for planned outage to replace the B reactor recirculation pump seal package. A reactor startup was performed on November 16 and full RTP was achieved on November 18. On December 3, power was reduced to 80 percent to remove the E main condenser water box from service due to a tube leak. Power was restored to full RTP later that day. On December 6, power was reduced to 65 percent to swap steam jet air ejectors, plug leaking main condenser tubes, and perform turbine and main steam isolation valve (MSIV) testing. Power was restored to full RTP later that 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 (71111.01 - Three samples)

.1 Occurrences of Adverse Weather (One sample)

a. Inspection Scope

On October 28, 2008, the inspectors reviewed NMPNSs actions in response to a storm in the vicinity of the station with wind gusting to 50 miles per hour. The inspectors verified that both units implemented actions specified in their respective adverse weather procedures to minimize the potential impact of the storm on the station. Unit 1 arranged for deferral of offsite maintenance on one of the two 115 kilovolt (kV) offsite power lines (line 4) that had been planned for that day. Unit 2 postponed maintenance on the Division 2 emergency diesel generator (EDG) until the following day, and deferred diving operations in the service water (SW) intake bay to allow the traveling screens to be placed in service. The storm had no adverse affect on the operation of either unit. Documents reviewed for each section are listed in the Attachment.

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. The inspectors reviewed and verified completion of the operations department cold weather preparation checklists contained in procedures N1-OP-64 and N2-OP-102, Meteorological Monitoring, for Units 1 and 2, respectively. The inspectors toured selected areas at Unit 1 and Unit 2 to verify cold weather readiness. Additionally, the inspectors assessed the readiness of the following risk significant systems that could be susceptible to the effects of cold weather:

  • Unit 1 SW system;
  • Unit 2 SW system.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04 - Three 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 updated final safety analysis report (UFSAR). The inspectors verified the operability of critical system components by observing component material condition during the system walkdown.

The inspectors performed partial walkdowns of the following systems:

  • Unit 2 Division 1 EDG while the Division 2 EDG was inoperable and unavailable; and

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05Q - Five samples)

a. Inspection Scope

The inspectors toured areas important to reactor safety at NMPNS to evaluate the stations 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 screen house;
  • Unit 1 diesel fire pump room;
  • Unit 2 low pressure core spray pump room, north auxiliary bay 175 foot elevation;
  • Unit 2 Division 1 cable spreading room, control building (CB) 237 foot elevation; and
  • Unit 2 Division 1 switchgear room, CB 261 foot elevation.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review (71111.11Q - 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 November 4, 2008, the inspectors observed Unit 1 LORT to assess operator and instructor performance during a scenario involving loss of reactor protection system motor generator 131, spurious opening of an emergency relief valve, and a steam leak with failure of a torus-to-drywell vacuum breaker. The inspectors evaluated the performance of risk significant operator actions including the use of special operating procedures (SOPs) and emergency operating procedures (EOPs).
  • On October 14, 2008, the inspectors observed Unit 2 LORT to assess operator and instructor performance during a scenario involving a main turbine electro-hydraulic control system pressure regulator malfunction that caused power to increase, a control rod drifting out of the core, a loss of all reactor building closed loop cooling system main pumps, and a failed-open safety relief valve with a break in the tailpiece above the suppression chamber that required operators to perform a reactor pressure vessel blowdown due to high drywell pressure. 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.

.2 Biennial Review (71111.11B - One sample)

a. Inspection Scope

The following inspection activities were performed using NUREG 1021, Operator Licensing Examination Standards for Power Reactors, Revision 9, Supplement 1, Inspection Procedure Attachment 71111.11, Licensed Operator Requalification Program, Appendix A, Checklist for Evaluating Facility Testing Material, and Appendix B Suggested Interview Topics.

A review was conducted of recent operating history documentation found in inspection reports, licensee event reports (LERs), the licensees corrective action program (CAP),and the most recent NRC plant issues matrix. The inspectors also reviewed specific events from the licensees CAP which indicated possible training deficiencies, to verify that they had been appropriately addressed. The senior resident inspector was also consulted for insights regarding licensed operators performance. These reviews indicated a potential area for improvement in recognizing off normal equipment status below any alarm threshold.

The operating and written tests for two of the six exam weeks were reviewed for quality and performance. Compliance with overlap controls of the facility program was verified.

On September 19, 2008, the results of the Unit 1 biennial written examination for 2008 and the annual operating tests for both units for 2008 were reviewed against the criteria of NUREG-1021, Operator Licensing Examination Standards for Power Reactors, Revision 9, Supplement 1, and NRC Manual Chapter 0609, Appendix I, Operator Requalification Human Performance SDP. The review verified the following:

For Unit 1

$ Crew pass rates were greater than 80% (Pass rate was 83.3%);

$ Individual pass rates on the written exam were greater than 80% (Pass rate was 97.3%);

$ Individual pass rates on the job performance measures (JPMs) of the operating exam were greater than 80% (Pass rate was 97.3%); and

$ More than 75% of the individuals passed all portions of the exam (86.5% of the individuals passed all portions of the examination).

For Unit 2

$ Crew pass rates were greater than 80% (Pass rate was 100%);

$ No biennial written examination was administered this year;

$ Individual pass rates on the JPMs of the operating exam were greater than 80%

(Pass rate was 98%); and

$ More than 75% of the individuals passed all portions of the exam (90% of the individuals passed all portions of the examination).

Observations were made of the dynamic simulator exams and JPMs administered during the week of the inspection. These observations included facility evaluations of crew and individual performance during the dynamic simulator exams and individual performance of five JPMs.

The remediation plans for one crew operating test failure and four individual operating test failures were reviewed to assess the effectiveness of the remedial training.

Operators, instructors and training/operations management were interviewed for feedback on their training program and the quality of training received.

Simulator performance and fidelity were reviewed for conformance to the reference plant control room.

A sample of administrative records was reviewed for compliance with license conditions, including NRC regulations. This sample included one year of requalification attendance records, two years of licensed operator watchstanding proficiency and license reactivation records, and ten licensed operator medical records.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12Q - Two 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 stations 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 sites ability to identify and address common cause failures and to trend key parameters.

The following maintenance rule inspection samples were reviewed:

  • Unit 1 emergency cooling system, based on repeat problems with main steam vent isolation valves; and
  • Unit 2 RCIC system, based on repeated trip relay failures.

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.

Unit 1

  • Week of October 6, which included containment spray 122 quarterly surveillance, EDG 103 monthly surveillance, and an emergent activity to perform power suppression testing to identify and suppress a leaking fuel bundle.
  • Week of November 3, which included EDG 103 monthly surveillance, containment spray 121 quarterly surveillance and heat exchanger performance testing, an extended maintenance period for 12 instrument air compressor, off-site 115 kV line 4 out of service for two days for off-site maintenance, and calibration of the average power range monitoring system using the traversing in-core probe system.
  • Week of November 17, which included 111 and 121 core spray system quarterly surveillances, 111 containment spray heat exchanger performance testing, a three day outage for EDG 102 to clean the fuel oil storage tank, and EDG 102 monthly surveillance.

Unit 2

  • Week of October 13, which included SW intake bay cleaning, Division 1 EDG monthly surveillance, a two day maintenance period for the Division 1 residual heat removal (RHR) system, Division 1 RHR quarterly surveillance, a power reduction to 65 percent for a control rod pattern exchange and single control rod scram time testing, and an emergent issue to repair the B SW pump after failure of the outboard pump bearing.
  • Week of November 3, which included RCIC system quarterly surveillances, SW intake bay cleaning, and emergent maintenance to replace broken shear pins for the B SW discharge strainer and to remove foreign material from the C and F SW pumps.
  • Week of December 1, which included Division 2 standby liquid control system valve maintenance and quarterly surveillance, Division 2 SW pumps quarterly surveillance, Division 2 EDG annual 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run surveillance, and emergent maintenance to repair the E SW discharge strainer. In addition, the week included the identification of lake water inleakage to the condensate system which led to a 20 percent power reduction to remove the E main condenser waterbox from service, and a subsequent power reduction to 65 percent to conduct repairs and swap steam jet air ejectors.

b. Findings

Introduction.

An NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," was identified on November 8, 2008 in that NMPNS did not take prompt action to verify that SW pump performance had not been adversely affected following the inadvertent introduction of a cleaning hose into the pump suction lines. This resulted in delayed identification of two inoperable Unit 2 SW pumps due to fouling of the impellers by foreign material that had been drawn into the pumps on November 4, 2008.

Description.

The Unit 2 SW system has six pumps (A-F), with three in each of the two Divisional subsystems (A, C, and E in Division 1, and B, D, and F in Division 2). The subsystems are normally cross-connected, with two pumps operating in each subsystem.

On the morning of November 4, 2008, divers were cleaning the Unit 2 SW intake bay using a vacuum device that was connected to a six inch diameter plastic hose. At 11:43 a.m., operators in the control room received an alarm that indicated low suction pressure for the Division 1 SW pumps, and observed decreased discharge flow from the 'C' SW pump. The control room operators contacted the diving supervisor, who informed them that the cleaning vacuum hose had inadvertently been drawn into the suction pipe for the

'C' SW pump. The E SW pump was started to allow the 'C' SW pump to be secured, and the hose was withdrawn. At about 12:45 p.m., a similar event occurred with the 'F' SW pump; the 'C' SW pump was started, the 'F' SW pump was secured, and the hose was withdrawn. Cleaning operations were secured and the cleaning vacuum hose was removed from the water. Although the end of the hose had broken into several pieces, NMPNS determined incorrectly that all of the hose had been retrieved.

Later on November 4, the inspectors noted that the discharge flow for the 'C' SW pump appeared to be lower than normal. The control room operators responded that the lower flow was normal for the existing pump combination.

On November 7, 2008, the 'F' SW pump was started as part of a planned pump swap.

This was the first time that the pump had been operated since it had been secured on November 4 to allow removal of the cleaning vacuum hose. An operator reported that the pump had made an abnormal noise just after it had been started, and control room operators observed abnormally low discharge flow. The 'F' SW pump was secured and declared inoperable. Disassembly of the pump revealed that approximately five feet of cleaning vacuum hose was lodged in the pump casing and impeller. The 'F' SW pump was restored to a functional status on November 8 at 5:31 p.m.

Because the November 7 issue with the 'F' SW pump confirmed that all of the cleaning vacuum hose had not actually been retrieved on November 4, the inspectors questioned whether additional action would be taken to verify that the 'C' SW pump had not been similarly impacted. NMPNS indicated that the SW pump quarterly surveillance would be performed to verify the operability of all of the remaining SW pumps. During this test, operators were unable to achieve the required parameters for the 'C' SW pump, and the pump was declared inoperable. Test results for the remaining SW pumps were satisfactory. On November 9 at 2:54 a.m., the 'C' SW pump was declared unavailable to support disassembly; approximately one foot of cleaning suction hose was found lodged in the impeller. The 'C' SW pump was returned to a functional status at 5:45 p.m. on November 9.

NMPNS engineering subsequently determined that the 'C' SW pump had been functional between November 4, when the hose had been sucked into the pump, and November 9, when the pump was declared inoperable and disassembled. The inspector agreed with this determination, because, while the pump was inoperable (pump differential pressure degraded below the in-service test requirement), it still would have supported SW system operability in combination with any of the remaining operable SW pumps.

As immediate corrective action for this event, the affected pumps were disassembled and the foreign material was removed. These issues were entered into the CAP as condition report (CR) 2008-8430 for the 'F' SW pump and CR 2008-8444 for the 'C' SW pump.

The performance deficiency associated with this event was that NMPNS did not promptly verify that ingestion of the cleaning vacuum hose into the 'C' and 'F' SW pump suction lines had not adversely affected the performance of the pumps. Corrective action to address the failure to promptly verify SW pump operability is being addressed by CR 2008-8492.

Analysis.

The finding is more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone and affects the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Per inspection manual chapter (IMC) 0609, Attachment 0609.04, Initial Screening and Characterization of Findings, the inspectors conducted a Phase 1 screening and determined that this finding required a Phase 2 analysis because the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment functions would not be available.

The inspectors determined that the finding was of very low safety significance (Green)using the Unit 2 plant-specific Phase 2 pre-solved worksheets, which include large early release frequency and external events, in accordance with IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations.

The following assumptions were made during the evaluation: 1) the reactor was operating at full power; 2) the 'C' SW pump was functional while the 'F' SW pump was not functional; 3) the 'F' SW pump was unavailable for greater than three days but less than 30 days (approximately 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> from when the hose was drawn into the suction pipe and the pump was secured on November 4 until it was restored to available status on November 8); and 4) the approximately 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> that the C SW pump was not functional (November 9, while the pump was disassembled), would not add significantly to the result.

The risk increase was dominated by the internal core damage frequency increase which was conservatively estimated to be in the mid E-7/year range. The dominate core damage sequence was based on the increased frequency of a loss of SW initiating event, due to loss of SW pump redundancy, and included the failure of containment heat removal, failure to vent the containment, and failure of low pressure injection sources following containment failure.

The finding had a cross-cutting aspect in the area of human performance because NMPNS did not use conservative assumptions in decision making, in that they did not timely verify the assumption that the cleaning hose was fully retrieved and had not impacted operability of the service water pumps (H.1.b per IMC 0305).

Enforcement.

10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," states, in part, "Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformance are promptly identified and corrected." Contrary to the above, on November 4 until November 8, 2008, NMPNS did not promptly identify that introduction of foreign material into the 'C' and 'F' SW pump suction lines had degraded the 'C' and 'F' SW pumps. This resulted in inoperability of the pumps. Because this noncompliance is of very low safety significance and was entered into the CAP as CRs 2008-8430, 2008-8444, and 2008-8492, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000410/2008005-01, Untimely Corrective Action for Degraded Service Water Pumps)

1R15 Operability Evaluations (71111.15 - Five 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 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 / 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 2008-8383 concerning the post-accident monitoring reliability of Unit 1 drywell pressure instruments following a postulated fuel failure and design basis loss of coolant accident;
  • CR 2008-8680 concerning Unit 1 EDG 102 fuel oil storage tank wall pitting;
  • CR 2008-7690 concerning divergence of two channels of the Unit 2 leak detection system differential temperature monitors for the main steam tunnel;
  • CR 2008-8405 concerning the continued operability of the B SW pump without strainer backwash in service due to broken shear pins in the rotating mechanism; and
  • CR 2008-8518 concerning the Unit 2 TS-required determination of acceptability for continued operation of the reactor coolant system following a cooldown of greater than 100 degrees Fahrenheit (F) in a one hour period.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications (71111.18 - One sample)

a. Inspection Scope

The inspectors reviewed a Unit 2 temporary modification that installed a blowdown valve at a low point of the instrument air system for removal of condensation in the system. It was installed to reduce air moisture content and prevent condensation in air operated components that could result in component malfunction. The inspectors reviewed the modification package and discussed its installation with mechanical engineering personnel. The inspectors evaluated the modification against the system design attributes listed in Unit 2 UFSAR Section 9.3.1.1, "Instrument Air System."

b. Findings

No findings of significance were identified.

1R19 Post Maintenance Testing (71111.19 - Four 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, Work Order (WO) 08-01313-00 to replace solenoid operated valves 113-273 and 113-274 for air operated valves 44.2-18 and 44.2-15 that control the vent and drain valves for the scram discharge volume, due to slow closure time after the October 23 scram. The PMT was to stroke time the vent and drain valves open and closed, in accordance with the WO step text.
  • Unit 1, WO 07-03553-00 for preventive maintenance on drywell nitrogen containment isolation valve air regulators. The PMT was to exercise the valves in accordance with procedure N1-ST-Q5, Primary Containment Isolation Valves Operability Test.
  • Unit 2, WO 08-18322-00 to replace solenoid valves 2MSS*SOV7C-1, -2, and -3 for MSIV 2MSS*7C, due to the MSIV having cycled without operator action following slow closure. The PMT was to perform 2MSS*7C fast closure stroke timing in accordance with N2-OSP-MSS-CS001, "MSIV Operability Test," perform 2MSS*7C slow closure in accordance with N2-OP-1, "Main Steam System," and verify proper solenoid operating currents in accordance with N2-OSP-LOG-W001, "Weekly Checks."

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20 - Two samples)

.1 Unit 1 Forced Outage

a. Inspection Scope

The inspectors observed and reviewed the following activities during the Unit 1 forced outage from October 23 to October 26, 2008.

The inspectors observed portions of the plant shutdown and cooldown and verified that the TS cooldown rate limits were satisfied. The inspector reviewed outage schedules and procedures, and verified that TS specified safety system availability was maintained and that shutdown risk was considered.

The inspectors observed portions of the reactor startup following the outage, and verified through control room observations, discussions with personnel, and log reviews that safety-related equipment specified for mode change was operable.

b. Findings

No findings of significance were identified.

.2 Unit 2 Planned Outage

a. Inspection Scope

The inspectors observed and reviewed the following activities during the Unit 2 planned outage from November 13 to November 16, 2008.

The inspectors observed portions of the plant shutdown and cooldown. The inspectors reviewed outage schedules and procedures, and verified that TS specified safety system availability was maintained and that shutdown risk was considered.

The inspectors performed a walkdown of accessible areas of the drywell to identify evidence of reactor coolant system leakage, and verify the condition of drywell coatings, structures, valves, piping, supports, and other equipment.

The inspectors observed portions of the reactor startup following the outage, and verified through control room observations, discussions with personnel, and log reviews that safety-related equipment specified for mode change was operable.

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 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 surveillance tests were reviewed:

  • N1-ST-M1A, Liquid Poison Pump 11 Operability Test;
  • N2-OSP-RHS-Q@006, RHR System Loop C Pump and Valve Operability Test and System Integrity Test; and
  • N2-ESP-ENS-Q731, "Quarterly Channel Functional Test of LPCS/LPCI [low pressure core spray/low pressure coolant injection] Pumps A, B, and C (Normal and Emergency Power) Auto Start Time Delay Relays."

b. Findings

No findings of significance were identified.

RADIATION SAFETY

2OS1 Access Control to Radiologically Significant Areas (71121.01 - Seven samples)

a. Inspection Scope

The inspectors reviewed all licensee performance indicators (PIs) for the occupational radiation safety cornerstone for follow-up.

The inspectors reviewed the licensees self assessments, audits, LERs, and Special Reports related to the access control program since the last inspection. The inspectors verified that identified problems were entered into the CAP for resolution.

The inspectors reviewed corrective action reports related to access controls. The inspectors interviewed staff and reviewed documents to determine if the activities are being conducted in an effective and timely manner commensurate with their importance to safety and risk:

  • Initial problem identification, characterization, and tracking;
  • Disposition of operability/reportability issues;
  • Evaluation of safety significance/risk and priority for resolution;
  • Identification of repetitive problems;
  • Identification of contributing causes;
  • Identification and implementation of effective corrective actions;
  • Resolution of NCVs tracked in the corrective action system; and
  • Implementation/consideration of risk significant operational experience feedback.

For repetitive deficiencies or significant individual deficiencies in problem identification and resolution identified above, the inspectors determined if the licensees self-assessment activities were also identifying and addressing these deficiencies.

The inspectors reviewed licensee documentation packages for all PI events occurring since the last inspection. The inspectors determined if any of these PI events involved dose rates >25 rad per hour (R/hr) at 30 centimeters or >500 R/hr at 1 meter. If so, the inspectors determined what barriers had failed and if there were any barriers left to prevent personnel access. For unintended exposures >100 millirem (mrem) total effective dose equivalent (TEDE) (or >5 rem skin dose equivalent (SDE) or >1.5 rem lens dose equivalent (LDE)), the inspectors determined if there were any overexposures or substantial potential for overexposure.

The inspectors reviewed any radiological problem reports since the last inspection which were attributed to radiation worker errors. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors determined if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. The inspectors discussed with the radiation protection manager any problems with the correction actions planned or taken.

The inspectors reviewed any radiological problem reports since the last inspection which were attributed to radiation protection technician errors. The inspectors determined if there was an observable pattern traceable to a similar cause. The inspectors determined if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

The inspectors evaluated licensee performance against the requirements contained in 10 CFR 20, Unit 1 TS 6.7 and Unit 2 TS 5.7.

b. Findings

No findings of significance were identified.

2OS2 ALARA Planning and Controls (71121.02 - Two samples)

a. Inspection Scope

The inspectors reviewed the licensees self assessments, audits, and Special Reports related to the as low as reasonably achievable (ALARA) program since the last inspection.

The inspectors determined if the licensees overall audit programs scope and frequency (for all applicable areas under the Occupational Radiation Safety Cornerstone) met the requirements of 10 CFR 20.1101(c).

For repetitive deficiencies or significant individual deficiencies in problem identification and resolution identified above, the inspectors determined if the licensees self-assessment activities were also identifying and addressing these deficiencies.

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

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03 - Two samples)

a. Inspection Scope

The inspectors reviewed CAP reports related to exposure significant radiological incidents that involved radiation monitoring instrument deficiencies since the last inspection in this area. The inspectors interviewed staff and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:

  • Initial problem identification, characterization, and tracking;
  • Disposition of operability/reportability issues;
  • Evaluation of safety significance/risk and priority for resolution;
  • Identification of repetitive problems;
  • Identification of contributing causes;
  • Identification and implementation of corrective actions which will achieve lasting results;
  • Resolution of NCVs tracked in corrective action system(s); and
  • Implementation/consideration of risk significant operational experience feedback.

For repetitive deficiencies or significant individual deficiencies in problem identification and resolution identified above, the inspectors determined if the licensees self-assessment activities are also identifying and addressing these deficiencies.

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

b. Findings

No findings of significance were identified.

2PS2 Radioactive Material Processing and Transportation (71122.02 - Six samples)

a. Inspection Scope

The inspectors reviewed the solid radioactive waste system description in the UFSAR and the recent radiological effluent release report for information on the types and amounts of radioactive waste disposed. The inspectors reviewed the scope of the licensees audit program to verify that it meets the requirements of 10 CFR 20.1101(c).

The inspectors walked-down the liquid and solid radioactive waste processing systems to verify and assess that the current system configuration and operation agree with the descriptions contained in the UFSAR and in the Process Control Program (PCP). The inspectors reviewed the status of any radioactive waste process equipment that was not operational and/or was abandoned in place. The inspectors reviewed the licensees administrative and physical controls to ensure that the equipment will not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure.

The inspectors reviewed the adequacy of any changes made to the radioactive waste processing systems since the last inspection. The inspectors verified that the changes were reviewed and documented in accordance with 10 CFR 50.59, as appropriate. The inspectors reviewed the impact, if any, to radiation doses to members of the public. The inspectors reviewed current processes for transferring radioactive waste resin and sludge discharges into shipping/disposal containers to determine if appropriate waste stream mixing and/or sampling procedures, and methodology for waste concentration averaging, provide representative samples of the waste product for the purposes of waste classification as specified in 10 CFR 61.55 for waste disposal.

The inspectors reviewed the radio-chemical sample analysis results for each of the licensees radioactive waste streams. The inspectors reviewed the licensees use of scaling factors and calculations used to account for difficult-to-measure radionuclides.

The inspectors verified that the licensees program assures compliance with 10 CFR 61.55 and 10 CFR 61.56 as required by Appendix G of 10 CFR Part 20. The inspectors reviewed the licensees program to ensure that the waste stream composition data accounts for changing operational parameters and thus remains valid between the annual or biennial sample analysis update.

The inspectors observed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors verified that the requirements of any applicable transport cask Certificate of Compliance had been met. The inspectors verified that the receiving licensee is authorized to receive the shipment packages. The inspectors observed radiation workers during the conduct of radioactive waste processing and radioactive material shipment preparation activities.

The inspectors determined if the shippers were knowledgeable of the shipping regulations and whether shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport with respect to NRC Bulletin 79-19 and 49 CFR Part 172 Subpart H. The inspectors verified that the licensees training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.

The inspectors sampled non-excepted package shipment records. The inspectors reviewed these records for compliance with NRC and Department of Transportation (DOT) requirements.

The inspectors reviewed the licensees LERs, Special Reports, audits, State agency reports, and self assessments related to the radioactive material and transportation programs performed since the last inspection. The inspectors determined if identified problems are entered into the CAP for resolution. The inspectors reviewed corrective action reports written against the radioactive material and shipping programs since the previous inspection.

The inspectors interviewed staff and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:

  • Initial problem identification, characterization, and tracking;
  • Disposition of operability/reportability issues;
  • Evaluation of safety significance/risk and priority for resolution;
  • Identification of repetitive problems;
  • Identification of contributing cause;
  • Identification and implementation of effective corrective actions;
  • Resolution of NCVs tracked in corrective action system(s); and
  • Implementation/consideration of risk significant operational experience feedback.

For repetitive deficiencies or significant individual deficiencies in problem identification and resolution identified above, the inspectors determined if the licensees self-assessment activities were also identifying and addressing these deficiencies.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151 - Twelve samples)

a. Inspection Scope

The inspectors sampled NMPNS submittals for the 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 Performance Indicator Guideline, Revision 5, was used to verify the basis in reporting for each data element.

Cornerstone: Mitigating Systems

The inspectors reviewed NMPNSs submittals for the Mitigating System Performance Indicators (MSPIs) 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. The definitions and guidance in NEI 99-02, formed the basis for the review. The results were discussed with the cognizant engineering and licensing personnel. Operating data for the period of October 2007 through September 2008 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.

Cornerstone: Occupational Radiation Safety

The inspectors reviewed all licensee PIs for the Occupational Radiation Safety Cornerstone for follow-up. The inspectors reviewed a listing of licensee action reports for the period January 1, 2008, through November 17, 2008, for issues related to the Occupational Radiation Safety PI, which measures non-conformances with high radiation areas greater than 1R/hr and unplanned personnel exposures greater than 100 mrem TEDE, 5 rem SDE, 1.5 rem LDE, or 100 mrem to the unborn child.

The inspectors determined if any of these PI events involved dose rates >25 R/hr at 30 centimeters or >500 R/hr at 1 meter. If so, the inspector determined what barriers had failed and if there were any barriers left to prevent personnel access. For unintended exposures >100 mrem TEDE (or >5 rem SDE or >1.5 rem LDE), the inspector determined if there were any overexposures or substantial potential for overexposure. The inspectors compared the results with the reported data.

Cornerstone: Public Radiation Safety

The inspectors reviewed a listing of licensee action reports for the period January 1, 2008 through December 8, 2008 for issues related to the public radiation safety PI, which measures radiological effluent release occurrences per site that exceed 1.5 mrem/quarter (qtr) whole body or 5 mrem/qtr organ dose for liquid effluents; or 5 mrads/qtr gamma air dose, 10 mrads/qtr beta air dose; or 7.5 mrems/qtr organ doses from I-131, I-133, H-3 and particulates for gaseous effluents. The inspectors compared the results with the reported data.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152 - Four 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 NMPNSs 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 Semi-Annual Review to Identify Trends (One sample)

a. Inspection Scope

As specified by Inspection Procedure 71152, Identification and Resolution of Problems, the inspectors reviewed NMPNSs 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, such as system health reports, quality performance reports, quality assurance assessment reports, maintenance rule status reports, operator workaround lists, and the governing procedure. The inspectors review considered the period of June through November 2008.

b. Assessments and Observations No findings of significance were identified. The inspectors did not identify any equipment or performance trends that had not already been noted in departmental quarterly assessments. NMPNS had a low threshold for the identification of items in the CAP, which allowed for the identification of low-level trends before the issue became significant.

.3 Annual Sample - Unit 1 Operator Workarounds (One sample)

a. Inspection Scope

The inspectors reviewed the Unit 1 operator workarounds, operator burdens, and operations items of interest, defeated annunciators, control room deficiencies, and open operability determinations. The review focused on the reliability and availability of mitigating systems with particular focus on issues that had the potential to affect the ability of operators to respond to plant transients and events. Also, the inspectors reviewed the governing procedure, NAI-REL-02, Control of Operator Workarounds, Burdens, and Interests. The inspectors interviewed operations personnel on their knowledge of selected workarounds and the associated compensatory actions. In addition, the inspectors discussed with engineering and operations management the planned corrective actions for restoration of some of the degraded systems.

b. Assessment and Observations No findings of significance were identified. None of the identified issues, individually or in the aggregate, appear to have a negative impact on the ability of the operators to complete actions in procedures, or to significantly affect the timeliness of those actions.

The inspectors identified one issue which had been removed from the workaround list without adequate corrective actions being taken. Specifically, the inspectors identified that the Unit 1 Shutdown Cooling System outboard isolation valve (SDC IV-38-02), which was placed on the list in August 2004, was removed from the Operator Workaround List because the nonconforming condition was accepted-as-is.

Nine Mile Point administrative instruction NAI-REL-02, Control of Operator Workarounds, Burdens, and Interests, Section 3.5.2, states: A workaround / burden can be resolved as an Accept-As-Is condition. In this case the Operations Manager must approve the Accept-As-Is resolution. Section 3.5.3 states, in part, If a workaround will be resolved by an Accept-As-Is condition . . . Confirm that any compensatory/manual measures have been appropriately . . . proceduralized.

The issue was first documented in CR-2004-3921, dated August 30, 2004. The CR noted that the breaker for IV-38-02 tripped while trying to open the valve from the control room.

The cause was determined to be thermal binding; the valve has a solid wedge disc which is sensitive to temperature differentials between the valve body and disc. One of the corrective actions was to revise N1-OP-4, Shutdown Cooling System, to manually open the valve off the valve seat with a torque wrench, and then complete opening the valve from the control room. As part of the procedure change process, NMPNS completed a 10 CFR 50.59 Screening Form but failed to recognize/identify that the system operation was described in the Unit 1 UFSAR. The UFSAR,Section X.A.2, states that the shutdown cooling system may be manually actuated from the main control room. The consequence of the valve failing to open from the control room is a delay in the ability to place shutdown cooling in service by the normal means. Because the valve is not able to function as described in the UFSAR, the system is degraded; however, there is no affect on the safety-related function of the valve, which is to close automatically for containment isolation.

The failure to identify during the 10 CFR 50.59 screening process for a procedure change to N1-OP-04 that the change was not consistent with the Unit 1 UFSAR is considered a violation of minor significance. As such, this issue is not subject to enforcement action, in accordance with the NRCs Enforcement Policy.

.4 Annual Sample - Unit 2 Operator Workarounds (One sample)

a. Inspection Scope

The inspectors reviewed the Unit 2 operator workarounds, operator burdens, and operations items of interest, defeated annunciators, control room deficiencies, and open operability determinations. The review focused on the reliability and availability of mitigating systems with particular focus on issues that had the potential to affect the ability of operators to respond to plant transients and events. Also, the inspectors reviewed the governing procedure, NAI-REL-02, Control of Operator Workarounds, Burdens, and Interests. The inspectors interviewed operations personnel on their knowledge of selected workarounds and the associated compensatory actions. In addition, the inspectors discussed with engineering and operations management the planned corrective actions for restoration of some of the degraded systems.

b. Assessment and Observations No findings of significance were identified. None of the identified issues, individually or in the aggregate, appear to have a negative impact on the ability of the operators to complete action in procedures, or to significantly affect the timeliness of those actions.

.5 Annual Sample: Review of NMPNS Response to Generic Letter 2007-01 (One Sample)

a. Inspection Scope

The inspectors selected CRs 2007-0895 and 2007-1977 as a problem identification and resolution (PI&R) sample for a detailed follow-up review. CR 2007-0895 documented the applicability and response to Generic Letter (GL) 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients. CR 2007-1977 documented water leaking into both the control and reactor buildings from a Unit 2 Division 3 electrical raceway. The Unit 2 Division 3 electrical raceway supports the power cables from the Division 3 EDG in the control building to the high pressure core spray (HPCS) pump in the reactor building. The inspectors reviewed relevant CRs to ensure that issues associated with potentially submerged cables were fully identified, appropriately evaluated, and corrective actions were specified and prioritized to prevent recurrence. The inspectors discussed the issue with engineering personnel and reviewed work orders, maintenance procedures, drawings and completed surveillance and test procedures on the potential submerged cables.

b. Findings

The inspectors inspected NMPs evaluation of the GL and corrective actions taken to resolve the potential adverse condition documented in CR 2007-1977. Specifically, on April 1, 2007, a few months after receiving GL 2007-01, NMPNS identified a condition where water was leaking into both the control and reactor buildings indicating that the HPCS power cables were submerged in water. Then on May 7, 2007, NMPNS provided the requested information in GL 2007-01 to the NRC.

GL 2007-01 informed licensees of an increase in inaccessible or underground cable failure in the industry due to moisture-induced degradation. The GL discussed that periodic draining may decrease the rate of cable insulation degradation, but would not prevent cable failures. In addition, GL 2007-01 discussed that some licensees have detected cable degradation prior to failures through techniques for measuring and trending the condition of cable insulation.

Although NMPNS inspected and pumped down manholes every six months and tested the insulation resistance to ground (megger) of some inaccessible/underground power cables as part of the associated HPCS motors routine maintenance, the inspectors noted that NMPNS did not evaluate the potential impact of moisture-induced failure on the HPCS power cables. In addition, the inspectors were informed that NMPNS did not consider the GL recommendations because they believed the HPCS power cables were qualified for submergence and have had no failures of underground cables at the site.

The NRC reviewed NMPNSs HPCS power cable documentation to determine the HPCS power cables qualification for submerged conditions. The NRC identified that the HPCS power cables are very similar, if not identical to other power cables recently reviewed.

Based on the information provided by NMPNS, it was not clear that the HPCS power cables are qualified to be submerged for the life of the plant.

As a result, the submergence qualification of the HPCS power cables was a potential performance deficiency, in that 10 CFR 50, Appendix B, Criterion III requires that measures shall be established to ensure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. This issue is an unresolved item pending NMPNS providing documentation that the HPCS cables were purchased, tested and evaluated to be qualified for submergence for the life of the plant and NRC review of these documents. (URI 05000410/2008005-02, Qualification of HPCS Power Cables for Submergence)

4OA3 Followup of Events and Notices of Enforcement Discretion (71153 - One sample)

.1 Manual Scram due to EPR Failure

a. Inspection Scope

On October 23 at about 9:00 p.m., Unit 1 operators began to observe small oscillations in reactor pressure. They attempted to transfer pressure control from the electronic pressure regulator (EPR) to the mechanical pressure regulator (MPR) in accordance with N1-SOP-31.2, "Pressure Regulator Malfunctions;" however, the EPR would not disengage. At 9:26 p.m., when the pressure oscillations had turned into a decreasing trend in pressure, operators manually scrammed the reactor.

Following the scram, reactor vessel water level shrank to 36 inches (an expected response to a scram) and operators entered EOP-2, RPV Control. The high pressure coolant injection system initiated to restore normal water level. Following the main turbine trip, all of the turbine bypass valves (TBVs) opened and remained open due to the EPR failure. To regain pressure control, the operators closed the MSIVs at 9:28 p.m. Several minutes later, the EPR disengaged and pressure control transferred to the MPR. The TBVs closed, allowing operators to reopen the MSIVs. A normal plant cooldown to cold shutdown was then commenced using the TBVs. Cold shutdown conditions were achieved on October 24 at 9:32 a.m.

The inspectors responded to the control room and observed operators' responses to the event. The inspectors verified that operators responded in accordance with the applicable procedures. The inspectors confirmed that no emergency plan emergency action level thresholds had been exceeded and that the event was appropriately reported to the NRC.

The inspectors reviewed the circumstances surrounding the event. The inspectors monitored troubleshooting activities and corrective actions through attendance of outage update meetings, discussions with plant personnel, and review of records, including the post-scram review.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 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 NMPNSs 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.

.2 Temporary Instruction (TI) 2515/176 - Emergency Diesel Generator TS Surveillance

Requirements Regarding Endurance and Margin Testing

a. Inspection Scope

The objective of TI 2515/176, EDG TS Surveillance Requirements Regarding Endurance and Margin Testing, is to gather information to assess the adequacy of nuclear power plant EDG endurance and margin testing as prescribed in plant-specific TS. The inspectors reviewed EDG ratings, design basis event load calculations, surveillance testing requirements and EDG vendor specifications, and gathered information in accordance with TI 2515/176.

The inspectors assessment and information gathered while completing this TI was discussed with licensee personnel. This information was forwarded to the Office of Nuclear Reactor Regulation for further review and evaluation.

b. Findings

No findings of significance were identified.

4OA6 Meetings, including Exit

Exit Meeting Summary

The inspectors presented the inspection results to Mr. Keith Polson and other members of NMPNS management on January 23, 2009. NMPNS acknowledged that no proprietary information was involved.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

K. Polson, Vice President
P. Bartolini, Supervisor, Mechanical Engineering
S. Belcher, Plant Manager
W. Byrne, Manager, Nuclear Security
R. Dean, Director, Quality and Performance Assessment
C. Fisher, Senior Engineer (MSPI Coordinator)
J. Kaminski, Manager, Emergency Preparedness
J. Krakuszeski, Manager, Operations
J. Laughlin, Manager, Engineering Services
C. Nielsen, Supervisor, Engineering
T. Shortell, Manager, Training
S. Sova, Manager, Radiation Protection
H. Strahley, Unit 2 General Supervisor Operations
T. Syrell, Director, Licensing
J. Torbitt, Assistant Operations Manager
P. Walsh, Shift Manager (Operator Workaround Coordinator)

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000410/2008005-02 URI Qualification of HPCS Power Cables for Submergence (Section 4OA2)

Opened and Closed

05000410/2008005-01 NCV Untimely Corrective Action for Degraded Service Water Pumps (Section 13)

LIST OF DOCUMENTS REVIEWED

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