IR 05000336/2009002

IR 05000336-09-002, 05000423-09-002; on 01/01/09 - 03/31/09, Millstone Power Station Integrated Inspection Report and Exercise of Enforcement Discretion

ML091340064
Person / Time
Site:	Millstone
Issue date:	05/14/2009
From:	David Lew NRC/RGN-I/DRP/PB6
To:	Christian D Dominion Resources
BELLAMY RR
References
EA-09-044, FOIA/PA-2011-0115 IR-09-002
Download: ML091340064 (38)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION May 14, 2009

SUBJECT:

MILLSTONE POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000336/2009002 AND 05000423/2009002 AND EXERCISE OF ENFORCEMENT DISCRETION

Dear Mr. Christian:

On March 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Millstone Power Station Unit 2 and Unit 3. The enclosed inspection report documents the inspection results, which were discussed on April 9, 2009, with Mr. A. J. Jordan and other 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 self-revealing finding of very low safety significance (Green).

Additionally, a licensee-identified violation determined to be of very low safety significance is listed in the report. However, because of the very low safety significance and because it is entered into your corrective action program, the NRC is treating the licensee identified violation as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV 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 Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Millstone.

In addition, the inspectors reviewed Licensee Event Report 50-423/2008-005, which described the details associated with the failure to maintain 3FWS*V861, C steam generator (SG) drain line isolation valve fully closed. This valve was relied on to meet technical specification (TS)

containment penetration requirements during fuel movement in the Unit 3 containment from November 1-3, 2008. This was a violation of TS Section 3.9.4.c., which requires each penetration providing direct access from the containment atmosphere to the environment be closed by an isolation valve, blind flange, or manual valve or be capable of being closed under administrative control during movement of fuel within the containment building. A risk evaluation was performed and the issue was determined to be of very low safety significance.

Although this issue constitutes a violation of NRC requirements, the NRC determined that the failure to completely close the valve was not within Dominions ability to reasonably foresee and correct, and as a result, the NRC did not identify a performance deficiency associated with this condition. The NRCs assessment considered that the valve does not have position indication to provide an alternate means to verify valve position, there were no past condition reports (CR)

documenting difficulty in closing the valve, the work order (WO) documenting like for like valve replacement in 2007 did not indicate difficulty in operating the valve, and Dominion took corrective action to close the valve and enter the issue into their corrective action process.

Based on the results of the NRCs inspection and assessment, I have been authorized, after consultation with the Director, Office of Enforcement, and the Regional Administrator, to exercise enforcement discretion in accordance with Section VII.B.6 of the Enforcement Policy and refrain from issuing enforcement for this violation.

In accordance with Title 10 of the Code of Federal Regulations (CFR) Part 2.390 of the NRCs 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 by James W. Clifford Acting For/

David C. Lew, Director Division of Reactor Projects Docket Nos. 50-336, 50-423 License Nos. DPR-65, NPF-49 Enclosure: Inspection Report No. 05000336/2009002 and 05000423/2009002 w/Attachment: Supplemental Information cc w/encl:

J. Price, Vice President, Engineering, Dominion Fleet A. Jordan, Site Vice President, Millstone Station C. Funderburk, Director, Nuclear Licensing and Operations Support L. Morris, Plant Manager, Millstone Station W. Bartron, Supervisor, Station Licensing J. Spence, Manager Nuclear Training L. Cuoco, Senior Counsel C. Brinkman, Manager, Washington Nuclear Operations J. Roy, Director of Operations, Massachusetts Municipal Wholesale Electric Company First Selectmen, Town of Waterford B. Sheehan, Chair, NEAC P. Rathbun, Vice-Chair, NEAC E. Wilds, Jr., Ph.D, Director, State of Connecticut SLO Designee

SUMMARY OF FINDINGS

IR 05000336/2009-002, 05000423/2009-002; January 1, 2009 - March 31, 2009; Millstone

Power Station Unit 2 and Unit 3.

The report covered a three-month period of inspection by resident and region-based inspectors.

Two Green findings were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process. Findings for which the significance determination process (SDP) does not apply may be Green or be assigned a severity level after NRC management review. The NRCs 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: Initiating Events

Green.

A self-revealing finding of very low safety significance (Green) was identified for Dominions failure to control Unit 3 Steam Generator (SG) levels while operating at power. Specifically, Dominions failure to control SG levels resulted in a reactor trip while reducing power for a plant shutdown. Dominion entered this issue into their corrective action program (CR113512), and corrective actions included conducting just-in-time (JIT) training on low power feed station operation for licensed operators prior to reactor start up.

This finding is more than minor because it was associated with the Human Performance Attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. The inspectors conducted a Phase 1 screening, in accordance with IMC 0609, Significance Determination Process, and determined that the finding is of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. The inspectors determined that this finding had a cross cutting aspect in the area of Human Performance, Work Control, because Dominion did not coordinate work activities, consistent with nuclear safety, by incorporating actions to address the operational impact on control room personnel

[H.3.(b)]. (Section 4OA3.1).

Licensee-Identified Violations

One violation of very low safety significance, which was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and corrective actions are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Units 2 and 3 operated at or near 100 percent power throughout the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Seasonal Site Inspection

a.

Inspection Scope (1 Sample)

The inspectors reviewed Unit 3s readiness for seasonal cold weather. The inspectors reviewed applicable procedures and performed walkdowns of the heat tracing, hot water heating system, and space heaters to verify condition of the weather protection equipment and determine if they were configured in accordance with Dominion=s procedures. The inspectors reviewed the Unit 3 Updated Final Safety Analysis Report (UFSAR) and Technical Specifications (TS) and compared the analysis with procedure requirements to ascertain that procedures were consistent with the UFSAR. The inspectors performed partial walkdowns of the Unit 3 intake structures, service water (SW) systems, intake structure traveling screens, and condensate surge and storage tanks to determine the adequacy of equipment protection from the effects of seasonal cold weather. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 External Flooding Inspection

a.

Inspection Scope (1 Sample)

The inspectors evaluated Dominions protection from the effects of external flooding conditions at Units 2 and 3. The inspectors reviewed the Final Safety Analysis Report (FSAR) to identify the areas that could be affected by flooding. The inspectors reviewed applicable procedures to verify that the actions required in the event of flooding could reasonably be completed. The inspectors conducted a walkdown of the intake structures and flood doors to determine if the structures were as described in the FSAR and that the material condition of the structures and components was adequately maintained. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

(4 Samples)

The inspectors performed four partial system walkdowns during this inspection period.

The inspectors reviewed the documents listed in the Attachment to determine the correct system alignment. The inspectors conducted a walkdown of each system to determine if the critical portions of the selected systems were correctly aligned, in accordance with the procedures, and to identify any discrepancies that may have had an effect on operability. The walkdowns included selected switch and valve position checks, and verification of electrical power to critical components. Finally, the inspectors evaluated other elements, such as material condition, housekeeping, and component labeling.

The following systems were reviewed based on their risk significance for the given plant configuration:

Unit 2

• Train A motor driven Auxiliary Feedwater (AFW);

• B Emergency Diesel Generator (EDG);

Unit 3

• Train A Service Water (SW); and

• A EDG.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

(1 Sample)

The inspectors completed a detailed review of the alignment and condition of the Unit 3 containment recirculation spray system. The inspectors conducted a walkdown of the B train of the system to assess critical equipment, such as breakers and valves, and were found in good condition and proper alignment in accordance with procedures.

The inspectors also conducted a review of outstanding maintenance work orders (WO)to determine if any deficiencies could significantly affect system function. In addition, the inspectors reviewed the system health reports and corrective action database to determine whether equipment problems were being identified and appropriately resolved. The inspectors also interviewed the system engineer. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Quarterly Fire Protection Walkdowns

a. Inspection Scope

(7 Samples)

The inspectors performed walkdowns of seven fire protection areas. The inspectors reviewed Dominion's fire protection program to determine the required fire protection design features, fire area boundaries, and combustible loading requirements for the selected areas. The inspectors walked down these areas to assess Dominion's control of transient combustible material and ignition sources. In addition, the inspectors evaluated the material condition and operational status of fire detection and suppression capabilities, fire barriers, and any related compensatory measures. The inspectors compared the existing conditions of the areas to the fire protection program requirements to determine if all program requirements were being met. Documents reviewed during the inspection are listed in the Attachment. The fire protection areas reviewed included:

Unit 2

• A and B EDG Cubicles 14-6, Fire Areas A-15/A-16;

• Auxiliary Building Elevation -25-6 Fire Area A1, Zones B, E, F;

• Intake Structure Fire Area I-1, Zones A, B, and C; Unit 3

• Auxiliary Building East Floor Area Elevation 24-6, Fire Area AB-1, Zone C;

• Auxiliary Building West Floor Area Elevation 24-6, Fire Area AB-1, Zone D;

• Control Building West Switchgear Area, Elevation 4-6, Fire Area CB-1; and

• Auxiliary Building East and West MCC and Rod Control, Elevation 24-6, Fire Areas AB-5 and AB-6 Zone A.

b. Findings

No findings of significance were identified.

.2 Annual Fire Drill Observation

a. Inspection Scope

(1 Sample)

Unit 3 The inspectors observed personnel performance during an unannounced fire brigade drill on March 16, 2009, to evaluate the readiness of station personnel to fight fires. The drill simulated a fire in the Unit 3 generator exciter and bearing areas. The inspectors observed the fire brigade members using protective clothing, turnout gear, self-contained breathing apparatus and entering the fire area. The inspectors also observed the fire fighting equipment brought to the fire scene to evaluate whether sufficient equipment was available to effectively control and extinguish the simulated fire. The inspectors evaluated whether the permanent plant fire hose lines were capable of reaching the fire area and whether hose usage was adequately simulated. The inspectors observed the fire fighting directions and communications between fire brigade members. The inspectors observed the response of control room personnel during the drill. The inspectors also evaluated whether the pre-planned drill scenario was followed and observed the post drill critique to evaluate if the drill objectives were satisfied and that any drill weaknesses were discussed.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

(1 Sample)

The inspectors reviewed the flood protection measures for equipment in the Unit 3 Recirculation Spray System (RSS) Rooms. The inspectors evaluated Dominions protection of safety-related systems from internal flooding conditions. The inspectors performed a walkdown of the area, interviewed the system engineer, reviewed the internal flooding evaluation, and verified that preventive maintenance was being performed on critical flood protection detection equipment to ensure that equipment and conditions remained consistent with those indicated in the design basis and flooding evaluation documents. Documents reviewed during the inspection are listed in the

.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

a.

Inspection Scope (1 Sample)

The inspectors observed the as-found condition of the Unit 3 B EDG jacket water cooler and engine air cooler water heat exchangers after they were opened to verify that any adverse fouling concerns were appropriately addressed. The inspectors reviewed the results of the inspections against the acceptance criteria contained within the procedure to determine whether all acceptance criteria had been satisfied. The inspectors also reviewed the UFSAR to ensure that heat exchanger inspection results were consistent with the design basis. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a.

Inspection Scope (2 Samples)

The inspectors observed simulator-based licensed operator requalification training for Unit 2 on January 21, 2009, and for Unit 3 on January 27, 2009. The inspectors evaluated crew performance in the areas of clarity and formality of communications, ability to take timely actions, prioritization, interpretation and verification of alarms, procedure use, control board manipulations, oversight and direction from supervisors, and command and control. Crew performance in these areas was compared to Dominion management expectations and guidelines as presented in OP-MP-100-1000, AMillstone Operations Guidance and Reference Document.@ The inspectors compared simulator configurations with actual control board configurations. The inspectors also observed Dominion evaluators discuss identified weaknesses with the crew and/or individual crew members, as appropriate. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

(5 Samples)

The inspectors reviewed five samples of Dominion's evaluation of degraded conditions, involving safety-related structures, systems and/or components for maintenance effectiveness during this inspection period. The inspectors reviewed Dominions implementation of the Maintenance Rule. The inspectors reviewed Dominion=s ability to identify and address common cause failures, the applicable maintenance rule scoping document for each system, the current classification of these systems in accordance with 10 CFR 50.65 (a)(1) or (a)(2), and the adequacy of the performance criteria and goals established for each system, as appropriate. The inspectors also reviewed recent system health reports, Condition Reports (CR), apparent cause determinations, functional failure determinations, operating logs, and discussed system performance with the responsible system engineer. Documents reviewed during the inspection are listed in the Attachment. The specific systems/components reviewed were:

Unit 2

• Reserve Station Service Transformer (RSST);

• EDG, B;

• Pressurizer Heaters; Unit 3

• Normal Power NSST/RSST; and

• Engineered Safety Feature (ESF) Load Sequencer.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

(7 Samples)

The inspectors evaluated online risk management for emergent and planned activities.

The inspectors reviewed maintenance risk evaluations, work schedules, and control room logs to determine if concurrent planned and emergent maintenance or surveillance activities adversely affected the plant risk already incurred with out of service (OOS)components. The inspectors evaluated whether Dominion took the necessary steps to control work activities, minimize the probability of initiating events, and maintain the functional capability of mitigating systems. The inspectors assessed Dominion=s risk management actions during plant walkdowns. Documents reviewed during the inspection are listed in the Attachment. The inspectors reviewed the conduct and adequacy of risk assessments for the following maintenance and testing activities:

Unit 2

• January 9, 2009, Yellow risk due to B EDG, B High Pressure Safety Injection (HPSI) OOS, and high trip risk due to environmental factors;

• February 16, 2009, Green risk with a high trip risk due to Reactor Protection System (RPS) matrix logic and trip path relay test, the turbine-driven auxiliary feedwater (TDAFW) pump was OOS due to emergent work on 2MS-440 (main steam instrument isolation valve to PI-4191);

• February 18, 2009, Green risk with a high trip risk due to switchyard work, the A essential switchgear OOS, the station air compressor OOS and the F air compressor OOS;

• March 26, 2009, Yellow risk due to North Bus Outage high grid risk; Unit 3

• February 25, 2009, Green Risk impacting A Quench Spray System (QSS), Safety Injection (SI), and Residual Heat Removal (RHR) pumps due to maintenance on the room air conditioning (AC) unit, ACUS1A;

• February 27, 2009 Emergent repair of 3CHS*CV8152, outboard letdown isolation valve; and

• March 17 - 20, 2009, failure of normal level control valve 3HDL-LV37B1, resulting in a trip of the B heater drain pump and subsequent down power to 90 percent power.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

(6 Samples)

The inspectors reviewed operability determinations (OD). The inspectors evaluated the ODs against the guidance contained in NRC Inspection Manual Part 9900, Technical Guidance, Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety. The inspectors also discussed the conditions with operators and system and design engineers, as necessary. Documents reviewed during the inspection are listed in the Attachment. The inspectors reviewed the adequacy of the following evaluations of degraded or non-conforming conditions:

Unit 2

• OD 000253 Revision 1, pressurizer proportional heater failure and similar pressurizer back-up heater failures;

• CR324869, Refueling Water Storage Tank (RWST) cross-tied to non-safety related equipment;

• CR326558, Floor Drain Covered in the East End of the A EDG Room; Unit 3

• OD 000247 Rev. 0, 3SIH*V028 was replaced and field weld 43 (FW-43) did not have required Non-Destructive Examination (NDE) performed;

• OD 000248 Rev. 0, Air volume in B SIH discharge piping; and

• CR319295, Past operability determination of B SIH discharge line.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

a. Inspection Scope

(4 Samples)

To assess the adequacy of the modifications, the inspectors performed walk downs of selected plant systems and components, interviewed plant staff, and reviewed applicable documents, including procedures, calculations, modification packages, engineering evaluations, drawings, corrective action program documents, the UFSAR, and TS. For the modifications reviewed, the inspectors determined whether selected attributes (component safety classification, energy requirements supplied by supporting systems, seismic qualification, instrument setpoints, uncertainty calculations, electrical coordination, electrical loads analysis, and equipment environmental qualification) were consistent with the design and licensing bases. Design assumptions were reviewed to verify that they were technically appropriate and consistent with the UFSAR. For each modification, the 10 CFR 50.59 screenings or safety evaluations were reviewed, as described in Section 1R02 of this report. The inspectors also verified that procedures, calculations, and the UFSAR were properly updated with revised design information. In addition, the inspectors verified that the as-built configuration was accurately reflected in the design documentation and that post-modification testing was adequate to ensure the structures, systems, and components would function properly. A listing of documents reviewed is provided in the Attachment. The following modifications were reviewed:

(1) Unit 2 permanent modification, Removal of A and B Diesel Generator Service Water Inlet Strainer.

(2) Unit 2 temporary modification, re-termination of the power supply of two pressurizer heaters from the back-up electrical supply to the safety related power supply (L106), done to restore the proportional pressurizer heater banks to full capacity following the failure of two heaters.

(3) Unit 2 temporary modification, temporary leak encapsulation of body to bonnet leak at M22-CN-543, B SG feed pump suction vent

(4) Unit 3 temporary modification for Supplemental Heating of the Feedwater Isolation Valve Room was reviewed.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

(7 Samples)

The inspectors reviewed seven post-maintenance test (PMT) activities to determine whether the PMT adequately demonstrated that the safety-related function of the equipment was satisfied, given the scope of the work specified, and that operability of the system was restored. In addition, the inspectors evaluated the applicable test acceptance criteria to evaluate consistency with the associated design and licensing bases, as well as TS requirements. The inspectors also evaluated whether conditions adverse to quality were entered into the corrective action program for resolution.

Documents reviewed during the inspection are listed in the Attachment. The following maintenance activities and PMTs were evaluated:

Unit 2

• A Emergency Building Filtration System filter replacement on January 30, 2009;

• Encapsulation of the steam leak on 2-CN-543 condensate vent connection isolation valve on March 6, 2009; Unit 3

• Control Building AC Booster Pump 3SWP*P2A motor replacement on January 24, 2009;

• A SG Feed Line Isolation Valve 3FWS*CTV41A air line repair on February 3, 2009;

• T/Tavg Channel 4 Calibration on February 6, 2009, following repairs due to channel failure;

• Stepdown transformer replacement for 120V vital AC bus 3 on February 26, 2009; and

• Station Black Out (SBO) Diesel maintenance on 3/5/09.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a.

Inspection Scope (8 Samples)

The inspectors reviewed eight surveillance activities to determine whether the testing adequately demonstrated equipment operational readiness and the ability to perform the intended safety-related function. The inspectors attended pre-job briefings, reviewed selected prerequisites and precautions to determine if they were met, and observed the tests to determine whether they were performed in accordance with the procedural steps. Additionally, the inspectors reviewed the applicable test acceptance criteria to evaluate consistency with associated design bases, licensing bases, and TS requirements and that the applicable acceptance criteria were satisfied. The inspectors also evaluated whether conditions adverse to quality were entered into the corrective action program for resolution. Documents reviewed during the inspection are listed in the Attachment. The following surveillance activities were evaluated:

Unit 2

• SP 2664B and SP 2664C, A and B Charging Pump Pulsation Dampener Test, Revision 000-02 on February 2, 2009;

• SP 2605G-008 and SP 2605G-012, SG Blowdown and Sample Containment Isolation Valve (CIV) Stroke and Timing In Service Testing (IST), Facilities 1 & 2, Revision 000-04; Unit 3

• SP 3616A.1-016, Local Operation Test of 3MSS*MOV74A & 3MSS*MOV74C, Rev.

000-03 on January 15, 2009;

• SP 3712B-001, Pressurizer Heater Capacity Surveillance Testing, Rev. 006-03 on January 28, 2009;

• SP 3712NC-001, Vital Battery Charger Surveillance Load Testing, Rev. 007-01 on January 28, 2009;

• SP 3622.3-001, TDAFW Pump Operational Readiness Test, Rev. 014-02 (IST) on January 30, 2009;

• SP 3680.1-003, Containment Leakage Trending, Rev. 002-01 (Reactor Coolant System (RCS) leakage detection) on February 17, 2009; and

• SP 31002, Plant Calorimetric, Rev. 010-10 on March 12, 2009.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

.1 Classification and Notification During Requalification Training

a.

Inspection Scope (1 Sample)

The inspectors reviewed the operators emergency classification and notification completed during Unit 3 requalification training on January 27, 2009. The inspectors verified the classification and notification were accurate and timely.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access to Radiological Significant Areas (71121.01)

a. Inspection Scope

(10 Samples)

During the period February 23 - 26, 2009, the inspectors conducted the following activities to verify that the licensee was properly implementing physical, administrative, and engineering controls for access to locked high radiation areas (LHRA), and other radiological controlled areas (RCA) during normal power operations, and that workers were adhering to these controls when working in these areas. Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, relevant to Millstone Unit 2 and Unit 3 TS and the licensees procedures.

This activity represents the completion of 10 samples relative to this inspection area, which partially completes the annual inspection requirement of twenty one.

Plant Walkdown and Radiation Work Permit (RWP) Reviews

(1) The inspectors toured accessible RCAs in Unit 2 and Unit 3, and with the assistance of a radiation protection technician, performed independent radiation surveys of selected areas and components, to confirm the accuracy of survey data, and the adequacy of postings. Plant areas inspected included the Auxiliary Buildings, Waste Buildings, and Fuel Storage Buildings.

(2) The inspectors identified plant areas where radiological significant work activities were being performed. These activities included making preparations for a Unit 3 spent resin transfer and preparing for transferring high activity Tri-Nuke filters to a shipping container from the Unit 3 spent fuel pool. The inspectors reviewed the applicable RWPs and job history files for these activities, to determine if the radiological controls were acceptable, discussed the status of preparations with the Unit 3 Radiation Protection Supervisor, and reviewed the electronic dosimeter dose/dose rate alarm set points to determine if the set points were consistent with plant policy.

(3) The inspectors determined that there were no current RWPs for airborne radioactivity areas with the potential for individual worker internal exposures to exceed 50 mrem. The inspectors reviewed the daily quality control checks performed on various airborne counting instruments (SAC-4, BC-4) to confirm that the instruments were operational.

(4) The inspectors determined that during 2008, there were no internal dose assessments for any actual internal exposures that reached the reporting threshold of greater than 10 mrem Committed Effective Dose Equivalent (CEDE).

The inspectors also reviewed data for the five highest exposed individuals for 2008, the dose/dose rate alarm reports, related CRs, and determined that no exposure exceeded site administrative, regulatory, or performance indicator criteria. Additionally, the inspectors confirmed that no declared pregnant workers were employed during 2008.

Problem Identification and Resolution

(5) A review of Nuclear Oversight assessment reports and field observation reports were conducted to determine if dose significant jobs were routinely monitored, radiological protection programs were effectively evaluated, and problems related to implementing radiological controls were entered into the corrective action program for resolution.

(6) CRs associated with radiation protection control access that were initiated between October 2008 and February 2009, were reviewed and discussed with the licensee staff to determine if the follow-up activities were being conducted in an effective and timely manner, commensurate with their safety significance.

High Radiation Area and Very High Radiation Area Controls

(7) Procedures for controlling access to High Radiation Areas (HRA) and Very High Radiation Areas (VHRA) were reviewed to determine if the administrative and physical controls were adequate. The inspectors determined that a recently implemented corporate procedure (RP-AA-201, Access Controls for High and Very High Radiation Areas), provided additional controls over the replaced site procedure RPM 5.1.3, that was previously implemented. The inspectors also evaluated access controls for VHRA areas in Unit 3, by reviewing procedure OP 3361A, Personnel Access Control to the MID System Components Inside Containment, and interviewing control room personnel.

(8) Keys to VHRAs stored in the Unit 3 Control Room were inventoried and accessible. LHRAs were verified to be properly secured and posted during plant tours.

Radiation Worker and Radiation Protection Technician Performance

(9) Several radiological related CRs were reviewed to evaluate if the incidents resulted from repetitive worker errors and to determine if an observable pattern traceable to a similar cause was evident.

(10) The inspectors attended daily Unit 3 Radiation Protection department planning meetings to assess the timeliness of information and level of detail provided to technicians for ongoing tasks. Radiation Protection Technicians and radworkers were questioned regarding their knowledge of plant radiological conditions and associated controls.

b. Findings

No findings of significance were identified.

2OS2 ALARA Planning and Controls (71121.02)a.

Inspection Scope (8 Samples)

During the period February 23 - 26, 2009, the inspectors verified that the licensee was properly implementing operational, engineering, and administrative controls to maintain personnel exposure as low as is reasonably achievable (ALARA) for past activities performed during 2008. Also reviewed were dose controls for current activities and preparations for the Unit 2 fall (2R19) 2009 refueling outage. Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, applicable industry standards, and the licensees procedures.

Radiological Work Planning

(1) The inspectors reviewed pertinent information regarding cumulative exposure history, current exposure trends, and ongoing activities to assess past 2008 performance and dose challenges for 2009, including the Unit 2 fall refueling outage (2R19).

(2) The inspectors reviewed the exposure data for tasks performed during 2008 and compared actual exposure with forecasted estimates. Included in this review were the tasks performed during the Unit 3 (3R12) refueling outage, on-line tasks performed for both operating units, and Unit 2 dry cask loading/storage operations.

(3) The inspectors evaluated the departmental interfaces between radiation protection, operations, maintenance crafts, and engineering to identify missing ALARA program elements and interface problems. The evaluation was accomplished by reviewing recent ALARA Council meeting minutes, ALARA Evaluations, departmental dose summaries, attending an ALARA Council meeting, and interviewing the ALARA coordinator.

The inspectors also reviewed the Radiation Protection Department Continuous Improvement Initiatives and the 5-year ALARA Plan (2007-2011) that identifies areas for further improving radiological controls.

Verification of Dose Estimates

(4) The inspectors reviewed the assumptions and basis for the annual 2008 site collective exposure projections for routine power operations and maintenance activities, and compared the estimated dose with the actual dose received by workers. The inspectors also reviewed the dose projections for the upcoming

2R19 refueling outage to determine the exposure challenges and preparations

being made for dose significant activities; e.g. thimble tube replacements.

(5) The inspectors reviewed the licensees procedures associated with monitoring and re-evaluating dose estimates when the forecasted cumulative exposure for tasks differed from the actual dose received. The inspectors reviewed the dose/dose rate alarm reports and exposure data for selected individuals receiving the highest total effective dose equivalent (TEDE) exposures for 2008 to confirm that no individual exposure exceeded the regulatory limit, or met the performance indicator reporting guideline.

Jobs-In-Progress

(6) The inspectors reviewed the RWPs, associated ALARA Evaluations (AE) and observed various preparations for jobs-in-progress performed at Unit 3, including transferring spent resin to a shipping cask (RWP3-09-17/AE3-09-02), and transferring spent Tri-Nuke mechanical filters to a waste disposal container (RWP 3-09-42/AE3-09-10).

(7) The inspectors reviewed recent AEs developed for controlling low dose tasks.

These AEs addressed various Unit 2 maintenance tasks including cleaning tanks T-20A/B (AE2-09-01), removal of fuel sipping equipment (AE2-09-09), RWST header vent testing (AE2-09-02), and a Unit 3 containment entry at power to perform a test on valve 3SIH-V028 (AE3-09-01).

Problem Identification and Resolution

(8) The inspectors reviewed elements of the licensees corrective action program related to implementing the ALARA program to determine if problems were being entered into the program for timely resolution. CRs related to controlling individual personnel exposure and programmatic ALARA challenges were reviewed.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

[OA]

4OA1 Performance Indicator (PI) Verification

.1 Cornerstone: Initiating Events

a. Inspection Scope

(2 Samples)

The inspectors reviewed Dominion submittals for the PIs listed below to verify the accuracy of the data reported during that period. The PI definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, ARegulatory Assessment Indicator Guideline,@ Revision 5, were used to verify the basis for reporting each data element.

The inspectors reviewed portions of the operations logs, monthly operating reports, and Licensee Event Reports (LER) and discussed the methods for compiling and reporting the PIs with cognizant licensing and engineering personnel. Documents reviewed during the inspection are listed in the Attachment.

Unit 3

• RCS Leak Rate from January 1, 2008 to December 31, 2008; and

• RCS Specific Activity from January 1, 2008 to December 31, 2008.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As required 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 Dominion's corrective action program. This was accomplished by reviewing the description of each new CR and attending daily management review committee meetings. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Annual Sample Review of Corrective Actions Related to Simulator Testing and Fidelity

a. Inspection Scope

(1 Sample)

The inspectors performed a focused review of the actions taken and planned in response to CR-108371 (Documentation of Simulator Testing Not Complete). The review included a sample of simulator tests that occurred during the period of time from 2006 to 2009 on both units. The inspectors reviewed root cause evaluations, associated CRs, corrective actions taken, technical evaluations, and planned corrective actions.

The inspectors also interviewed personnel and conducted a walkdown of the Unit 2 and Unit 3 simulators. Documents reviewed during the inspection are listed in the

.

b. Findings and Observations

No findings of significance were identified.

There were some significant deviations between the Unit 2 and Unit 3 core neutronics model and the reference plants. The licensee is currently taking credit for initial licensing reactivity manipulations in the simulator.

The Unit 2 and Unit 3 simulator control banks at 100% power (Unit 2 control bank 7, Unit 3 control bank D) differential rod worth coefficients were significantly less than the reference plant values in the upper half of the core. These values did not meet the requirements of ANS/ANSI-3.5-1998 section 4.1.3.2(1) for normal evolutions. This deviation caused the simulator core temperature response to be less than the reference plant during a rapid downpower maneuver. This deviation could potentially affect operator response during a rapid plant downpower. This deviation was first identified in 2006 and again in 2008 during Licensed Operator Requalification Inspections. The corrective action specified was to conduct a training needs assessment. The needs assessment had not yet been completed as of this inspection cycle. In addition, on Unit 3, control bank C integral rod worth was 52% higher, and shutdown bank A integral rod worth was 23% higher than the reference plant. These deviations from ANS/ANSI 3.5-1998 were also documented but were neither corrected nor properly addressed in the training program.

The Unit 2 simulator normal annual startup test had not been completed for refueling cycle 2R18. This test was later accomplished for 2R19. Simulator core performance tests had been completed for the beginning of cycle (BOC) conditions but not for middle of cycle (MOC) or end of cycle (EOC) conditions for 2R19. When taking credit for operator licensing reactivity manipulations in the simulator, the core performance fidelity should be verified for the same or similar conditions under which the manipulations are being credited.

The Unit 2 simulator response for 4160 VAC breaker closure when synchronizing between two power sources did not closely match the reference plant response. For example, while conducting an NRC Job Performance Measure (JPM) in the simulator (paralleling the Unit 2 RSST to the A EDG per EOP-2541 Restoring Electrical Power 23-H step 9), the operator was required to close breaker A302. Breaker A302 would not close in the simulator until after the sychroscope pointer was aligned at the 12:00 position. The procedure explicitly requires the operator to close the breaker when the sychroscope pointer passes the 11:00 position. If the operator performs the procedure as written, and releases the breaker prior to reaching the 12:00 position (because the pointer is moving slowly), the breaker will not close. The breaker in the reference plant will close between the 11:00 and 1:00 positions during the time when the check relay is activated. The same deviation was identified during previous initial license training (ILT) and licensed operator requalification training (LORT) exams. The problem had been the subject of a simulator Discrepancy Report (DR) after the 2005 Unit 2 initial licensing exam but the DR was closed without taking any corrective action or conducting a training needs assessment.

.3 Annual Sample Unit 3 Radiation Monitors

a. Inspection Scope

(1 Sample)

The inspectors performed a focused review of the Unit 3 radiation monitors in response to a number of issues associated with the monitors. The review included equipment issues from 2007 to 2009. The inspectors interviewed the system engineer, reviewed system health reports, CRs, associated maintenance rule evaluations and apparent cause evaluations, the (a)(1) action plan for RE16B, and planned corrective actions.

Documents reviewed during the inspection are listed in the Attachment.

b. Findings and Observations

No findings of significance were identified.

The inspectors identified that failures of maintenance rule performance criteria 105b for radiation monitors that are used to detect a SG tube event were not being tracked.

Specifically, there had been two failures in a 24 month period (criteria is less than four),neither of which had been recorded. The inspectors also identified that unavailability hours for performance criteria 1.07 had not been adequately tracked. Specifically, the system engineer knew that even though the unavailability hours associated with the loss of both PDP computers did not exceed the performance criteria, the engineer had not recorded the hours.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

.1 (Closed) LER 05000423/2008002-00, Failure of Four Main Steam Safety Valves to Lift

Within the Acceptance Criteria On October 9 and 10, 2008, with the plant at 100% power, four main steam safety valves failed to lift within the acceptance criteria (+/-3%) of TS 3.7.1.1. Dominion attributed the failures to corrosive oxide locking action between surface layer materials of the disk-seat interface, referred to as oxide locking. After testing, the safety valves were adjusted within +/-1% of the TS acceptance criteria. Dominion entered this issue into their corrective action process CR113238. The inspectors reviewed this LER and associated CRs. No findings were identified. This failure to comply with TS 3.7.1.1 constitutes a violation of minor significance that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. This LER is closed.

.2 (Closed) LER 05000423/2008005-00, Containment Penetration Not Fully Closed During

Fuel Movement On November 5, 2008, with the plant in Mode 6, operators discovered that 3FWS*V861, C SG drain line isolation valve, which was relied on to meet TS containment penetration requirements during fuel movement in containment, was not fully closed. TS 3.9.4.c requires that each penetration providing direct access from the containment atmosphere to the environment be closed by an isolation valve, blind flange, or manual valve or be capable of being closed under administrative control during movement of fuel within the containment building. Dominions investigation subsequently determined that the valve had been in this condition during fuel movements inside containment from 0430 on November 1, 2008 until 0915 on November 3, 2008. Operators identified that the valve was leaking while filling the C SG on November 5, 2008. They attempted to close the valve and were not successful until mechanical leverage was applied.

The inspectors reviewed the LER and Dominions apparent cause evaluation of the event. The inspectors determined that the failure to completely close valve 3FWS*V861 was not within Dominions ability to foresee and correct and was not a performance deficiency. Valve 3FWS*V861 does not have position indication. The operator who closed the valve and the operator who performed the independent verification did not have an alternate means to verify that the valve was completely closed. Additionally, when the valve was identified to be leaking while filling the SG, it was only able to be completely closed when mechanical leverage was applied. A review of previous work orders (WOs) revealed that the valve was replaced like for like in 2007 due to seat leakage. A different packing was used which required more force to consolidate. Also, the packing gland was torqued per procedure when, previously, the packing was tightened using good mechanical practices. Because of these changes, more force would be required to operate the valve; however, there was no indication in the 2007 WO that the valve was difficult to operate. A review of the CRs associated with this valve did not indicate any previous problems in operating the valve. Because of these details, the inspectors concluded that the inability to fully close valve 3FWS*V861 could not have reasonably been avoided or detected by Dominions quality assurance program or other related control measures. The inspectors also performed a Phase1 SDP analysis and determined the violation to be of very low safety significance (Green).

Dominions corrective actions included closing the valve, entering the issue into their corrective action process (CR 117527), changing the position verification procedure to specify physical verification versus visual, and plans to modify the valve during the next refueling outage to improve the stroking function. Therefore, in accordance with Section VII.B.6 of the Enforcement Policy, the NRC has chosen to exercise enforcement discretion and not issue a violation for this issue. This LER is closed.

.3 (Closed) LER 05000423/2008003-00, Automatic Reactor Trip During Shutdown for

Refueling Outage 3R12 On October 11, 2008, Unit 3 received an automatic reactor trip at approximately 30%

power, while the unit was reducing power in preparation for a refueling outage. The control room operators were in manual control of the feedwater system. The plant was experiencing SG level oscillations as a result of removing feedwater system components from service. Oscillations increased and the A SG reached its high-high setpoint, resulting in an automatic turbine trip and feedwater isolation. C and D SG levels shrank to their low-low level setpoint which caused an automatic reactor trip.

The inspectors witnessed Unit 3s reactor trip and observed plant response and operator actions in order to evaluate the performance of the mitigating systems and the control room operators. The inspectors also reviewed the post trip review report and root cause evaluation. Documents reviewed during the inspection are listed in the Attachment.

Introduction:

A self-revealing finding of very low safety significance (Green) was identified for Dominions failure to control Unit 3 SG levels while operating at power.

Specifically, Dominions failure to control SG levels resulted in a reactor trip while reducing power in preparation for a plant shutdown.

Description:

On October 11, 2008, Millstone Unit 3 was reducing power in preparation for its 12th refueling outage. An operator was stationed at main board 5 to remove the A Turbine Driven Feedwater Pump (TDFWP) from service when power was less than 50%. The operator remained in place and responded to numerous SG level oscillations.

TDFWP speed was raised out of the normal range to increase differential pressure (DP)across the feedwater regulating valves (FRVs) because the operator believed this would assist in controlling the level oscillations.

Another operator noticed the high DP and brought it to the attention of the unit supervisor. The unit supervisor stationed this operator at the feed station to restore feed to steam DP to normal. The operator lowered feed pump speed which caused the FRVs to open in order to maintain the same flow. As the FRVs opened, feed header pressure dropped and the operator increased feed pump speed to recover DP. This sent a large amount of relatively cold water to the SGs before the FRVs could be closed. As the water in the SGs expanded due to heating, levels in the A and B SGs reached the high-high setpoint. This caused a turbine trip and feedwater isolation. C and D SGs shrank to the low-low level setpoint, resulting in an automatic reactor trip.

Dominions root cause evaluation determined that the organization, with respect to monitoring and measuring crew performance, was not effective in implementing programs designed to manage challenges to the operators during a plant shutdown.

While the organization was aware of the challenges in manually operating the feed station, it did not identify the need to improve the feed stations overall performance via the corrective action process. Additionally, a decrease in proficiency in manual feed station operation at low power levels was not identified, lower power feed station operation was not covered in JIT training, and the feed station operator had not received JIT training. The root cause evaluation also determined that inadequate rigor for outage preparation expectations resulted in Operations being challenged prior to and during the shutdown. Also, the control room operators were distracted by numerous tagging-related shutdown activities during the shutdown.

Analysis:

The inspectors determined that Dominions failure to maintain control of Unit 3 SG levels was a performance deficiency. Specifically, the failure to control SG levels resulted in a reactor trip while reducing power in preparation for a plant shutdown.

Traditional enforcement does not apply because there were no actual safety consequences, impacts on the NRCs ability to perform its regulatory function, or willful aspects of the finding.

This finding is more than minor because it was associated with the Human Performance Attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, Dominions failure to control SG levels resulted in an automatic reactor trip while reducing power in preparation for a plant shutdown. The inspectors conducted a Phase 1 screening, in accordance with IMC 0609, Significance Determination Process, and determined that the finding is of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available.

The inspectors determined that this finding had a cross cutting aspect in the area of Human Performance, Work Control, because Dominion did not coordinate work activities, consistent with nuclear safety, by incorporating actions to address the operational impact on control room personnel [H.3.(b)].

Enforcement:

No violation of regulatory requirements occurred, because the main feed pumps, feed regulating and bypass valves, and SG level control system are not safety-related. Because this finding does not involve a violation of regulatory requirements and has very low safety significance, it is identified as a finding. Dominion entered this issue into their corrective action program (CR113512) and corrective actions included conducting training in low power feed station operation for licensed operators prior to reactor start up. (FIN 05000423/2009002-01, Failure to Control Steam Generator Water Levels Results in Automatic Reactor Trip)

.4 (Closed) LER 05000423/2008006-00, Turbine-Driven Auxiliary Feedwater Pump Steam

Trap Isolation Valves Found Closed On November 24, 2008, Dominion determined that at 0025, with the plant at 18% power, Unit 3 control room operators identified that the TDAFW pump steam trap isolation valves were closed. The TDAFW pump was declared inoperable and Technical Specification Action Statement (TSAS) 3.7.1.2.c was entered. The valves were promptly opened, steam traps blown down, the TDAFW pump restored to operable status and the TSAS exited at 0346. Dominions investigation determined that the valves were inoperable since November 22, 2008 at 1746, a total of 34 hours3.935185e-4 days <br />0.00944 hours <br />5.621693e-5 weeks <br />1.2937e-5 months <br />. During this 34 hour3.935185e-4 days <br />0.00944 hours <br />5.621693e-5 weeks <br />1.2937e-5 months <br /> period, the unit went through two mode changes (Mode 3 to Mode 1). This licensee-identified finding is a violation of TS 3.0.4 which in part requires that the TDAFW pump be operable prior to changing operational modes. The enforcement aspects of this finding are discussed in Section 4OA7. This LER is closed.

4OA5 Other Activities

.1 World Association of Nuclear Operators (WANO) Peer Review Report.

a. Inspection Scope

(1 Sample)

The inspectors reviewed the report for the WANO plant assessment of Millstone Nuclear Generating Station conducted June 2008. The inspectors reviewed the report to ensure that issues identified were consistent with the NRC perspectives of Millstone performance and to verify that the WANO team did not identify any safety significant issues requiring further NRC follow-up.

b. Findings

No findings of significance were identified.

4OA6 Meetings, including Exit

Exit Meeting Summary

On April 9, 2009, the resident inspectors presented the overall inspection results to Mr.

A. J. Jordan, and members of his staff. The inspectors confirmed that no proprietary information was provided or examined during the inspection.

4OA7 Licensee Identified Violations

The following violation of very low safety significance (Green) or Severity Level IV was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a Non-Cited Violation (NCV).

TS 3.0.4 states, in part, that entry into an operational mode shall not be made when the conditions for the Limiting Condition for Operation are not met and the associated action requires a shutdown if they are not met within a specified time interval. Contrary to this, from November 22, 2008 at 17:46 until November 24, 2008 at 03:46, Unit 3 did not meet the conditions for TS 3.7.1.2, AFW system due to an isolated steam trap, and transitioned from mode 3 to mode 1. Dominion restored the AFW system to operability and entered the issue into their corrective action process, CR120030. This finding is of very low safety significance because the finding does not involve a loss of system safety function or a loss of safety functions of a single train for greater than its TS allowed outage time.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

G. Auria Nuclear Chemistry Supervisor

B. Bartron Supervisor, Licensing

P. Baumann Manager, Security

C. Chapin Supervisor, Nuclear Shift Operations Unit 2

A. Chyra Nuclear Engineer, PRA

T. Cleary Licensing Engineer

G. Closius Licensing Engineer

L. Crone Supervisor, Nuclear Chemistry

J. Dorosky Health Physicist III

M. Finnegan Supervisor, Health Physics, ISFSI

R. Griffin Director, Nuclear Station Safety & Licensing

W. Gorman Supervisor, Instrumentation & Control

J. Grogan Assistant Operations Manager

C. Houska I&C Technician

A. Jordan Site Vice President

J. Kunze Supervisor, Nuclear Operations Support

B. Krauth Licensing, Nuclear Technology Specialist

J. Laine Manager, Radiation Protection/Chemistry

B. Barron Manager, Nuclear Oversight

P. Luckey Manager, Emergency Preparedness

R. MacManus Director, Engineering

M. OConnor Manager, Engineering

L. Morris Plant Manager

M. Roche Senior Nuclear Chemistry Technician

J. Semancik Manager, Operations

A. Smith Asset Management

S. Smith Supervisor, Nuclear Shift Operations Unit 3

J. Spence Manager, Training

S. Turowski Supervisor, Health Physics Technical Services

C. Vournazos IT Specialist, Meteorological Data

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Closed

05000423/2008002-00 LER Failure of Four Main Steam Safety Valves to Lift Within the Acceptance Criteria (Section 4OA3).

05000423/2008003-00 LER Automatic Reactor Trip During Shutdown for Refueling

Outage 3R12 (Section 4OA3).

05000423/2008005-00 LER Containment Penetration Not Fully Closed During Fuel Movement (Section 4OA3).

05000423/2008006-00 LER Turbine-Driven Auxiliary Feedwater Pump Steam Trap Isolation Valves Found Closed (Section 4OA3).

BASELINE INSPECTION PROCEDURE PERFORMED 71121.01 Access Controls to Radiological Significant Areas 2OS1 71121.02 ALARA Planning and Controls 2OS2