IR 05000293/2008002

IR 05000293-08-002, on 01/01/2008-03/31/2008; Pilgrim Nuclear Power Station; Maintenance Risk Assessments and Emergent Work Control

ML081160052
Person / Time
Site:	Pilgrim
Issue date:	04/24/2008
From:	Racquel Powell NRC/RGN-I/DRP/PB5
To:	Bronson K Entergy Nuclear Operations
Powell R, RI/DRP/610-337-6967
References
IR-08-002
Download: ML081160052 (34)

Text

ril 24, 2008

SUBJECT:

PILGRIM NUCLEAR POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000293/2008002

Dear Mr. Bronson:

On March 31, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Pilgrim Nuclear Power Station (PNPS). The enclosed report documents the results, which were discussed on April 8, 2008, with Mr. Robert Smith, General Manager Pilgrim Operations, and members of your staff.

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

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

This report documents one NRC-identified finding of very low safety significance (Green). The finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV), in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you contest the 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 the Pilgrim Nuclear Power Station.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosures, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Raymond J. Powell, Chief Projects Branch 5 Division of Reactor Projects Docket No. 50-293 License No. DPR-35 Enclosure: Inspection Report 05000293/2008002 w/Attachment: Supplemental Information cc w/encl:

Vice President, Operations, Entergy Nuclear Operations Senior Vice President, Entergy Nuclear Operations Vice President, Oversight, Entergy Nuclear Operations Senior Manager, Nuclear Safety & Licensing, Entergy Nuclear Operations Senior Vice President and COO, Entergy Nuclear Operations Assistant General Counsel, Entergy Nuclear Operations Director, Radiation Control Program, Commonwealth of Massachusetts W. Irwin, Chief, CHP, Radiological Health, Vermont Department of Health The Honorable Therese Murray The Honorable Vincent deMacedo Chairman, Plymouth Board of Selectmen Chairman, Duxbury Board of Selectmen Chairman, Nuclear Matters Committee Plymouth Civil Defense Director D. OConnor, Massachusetts Secretary of Energy Resources J. Miller, Senior Issues Manager Office of the Commissioner, Massachusetts Department of Environmental Protection Office of the Attorney General, Commonwealth of Massachusetts Electric Power Division, Commonwealth of Massachusetts R. Shadis, New England Coalition Staff D. Katz, Citizens Awareness Network W. Meinert, Nuclear Engineer J. Giarrusso, MEMA, SLO Commonwealth of Massachusetts, Secretary of Public Safety

SUMMARY OF FINDINGS

IR 05000293/2008-002; 01/01/2008-03/31/2008; Pilgrim Nuclear Power Station; Maintenance

Risk Assessments and Emergent Work Control.

The report covered a 13-week period of inspection by resident and region-based inspectors.

One Green finding, which was a non-cited violation (NCV), was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (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 nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.65(a)(4) for Entergy's failure to conduct an adequate risk assessment for emergent maintenance on the A5 Emergency Bus undervoltage relays. Specifically, the inspectors noted that Entergy had downgraded an on-line risk assessment from Red to Green without a valid technical basis and did not recognize the unavailability of the automatic function of the Emergency Diesel Generator (EDG); as a result, Entergy did not evaluate or specify risk management actions.

This finding is more than minor because the risk assessment had incorrect assumptions that changed the outcome of the assessment. The inspectors conducted a screening in accordance with IMC 0609, Significance Determination Process, Appendix K,

Maintenance Risk Assessment and Risk Management Significance Determination Process. The finding was determined to be of very low safety significance (Green)because the Incremental Core Damage Probability Deficit for the timeframe that the relays were removed from service was significantly less than 1E-6 due to the short amount of time the EDG was unavailable in the automatic mode and the reasonable assurance that operators could manually tie the EDG to the bus in the event of a Loss Of Offsite Power.

This finding has a cross-cutting aspect in the area of Human Performance, Decision Making, because Entergy did not use a systematic process to make a risk-significant decision, when faced with an unexpected plant condition. H.1(a) (Section 1R13)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Pilgrim Nuclear Power Station (PNPS) operated at or near 100 percent power during the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

(1 System Seasonal susceptibility sample including review of two risk significant systems)

The inspectors reviewed actions taken by the licensee for extreme cold weather during the week of January 20, 2008. The site experienced several days of below normal temperatures and Entergy implemented the Severe Cold Weather Actions specified in Procedure 8.C.40, Seasonal Weather Surveillance. The inspectors conducted the inspection on the night of January 20, 2008, and walked down selected areas addressed in the procedure to determine if cold weather damage had occurred. The inspectors also walked down exterior portions of the Fire Protection system, the Emergency Diesel Generator (EDG) rooms, the Diesel Fire Pump room and the Fire Equipment storage area.

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 partial walkdown of each system to determine if the critical portions of the selected systems were correctly aligned in accordance with these 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:

• Station Blackout Diesel Generator;

• B EDG Starting and Turbo-Boost Air following work on air compressors;

• Reactor Core Isolation Cooling system just prior to a High Pressure Coolant Injection system outage; and

• High Pressure Coolant Injection system while the A EDG was out-of-service for maintenance.

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 A EDG system to assess the functional capability of the system. The inspectors conducted a walkdown of the system to determine whether the critical components, such as valves and switches, were aligned in accordance with operating procedures and to identify any discrepancies that could have an effect on operability.

The inspectors discussed system health with the system engineer and conducted a review of outstanding maintenance work orders to determine whether the deficiencies significantly affected the A EDG system function. The inspectors also reviewed recent condition reports (CRs) to determine whether EDG equipment problems were being identified and appropriately resolved. Documents reviewed during the inspection are listed in the

.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Fire Protection - Tours

a. Inspection Scope

(6 samples)

The inspectors performed walkdowns of six fire protection areas during the inspection period. The inspectors reviewed Entergy'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 Entergy'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 then compared the existing condition of the areas to the fire protection program requirements to determine whether all program requirements were met. In addition, the inspectors reviewed the technical basis for a functionality assessment of the electric fire pump, following the failure to meet surveillance procedure acceptance criteria. Documents reviewed during the inspection are listed in the Attachment. The fire protection areas and capabilities reviewed were:

• Reactor Core Isolation Cooling - Fire Zone 1.5;

• Diesel Driven Fire Pump Room - Fire Zone 5.4;

• A Residual Heat Removal/Core Spray Quadrant - Fire Zone 1.1;

• Standby Gas Treatment System - Fire Zone 1.23;

• Spent Fuel Pool Cooling Pumps/Heat Exchanger Area - Fire Zone 1.13; and

• Electric Fire Pump Operational Status Review and Pump Room Walkdown.

b. Findings

No findings of significance were identified.

.2 Annual Fire Drill Observation

a. Inspection Scope

(1 sample)

The inspectors observed an announced fire drill in the tool crib in the Operations and Maintenance Building. The fire drill was conducted in accordance with plant procedure ENN-DC-189, Fire Drills. The inspectors observed performance of the fire brigade personnel to determine whether the licensees fire fighting pre-plan strategies were utilized, the pre-planned drill scenario was followed, and the drill objectives were met. The inspectors confirmed that, as appropriate, proper security and radiological controls were applied; proper protective clothing and breathing apparatus were donned; sufficient fire fighting equipment was brought to the scene; the fire brigade leaders fire fighting directions were clear; and communications with the plant operators and between fire brigade members were effective. The inspectors observed the drill critique to determine whether areas to improve fire brigade performance were identified. The inspectors verified that the licensee identified appropriate corrective actions for identified deficiencies and entered the issues into the corrective action program.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

===Internal Flooding Inspection

a. Inspection Scope

(1 sample)===

The inspectors walked down the Reactor Core Isolation Cooling pump room, Flood Zone RB-17C, and associated flood propagation pathways, to assess the effectiveness of Entergy's internal flood control measures. The inspectors assessed the condition of curbing, hatch and conduit seals, floor drains, and floor sump systems. The inspectors also evaluated whether potential sources of internal flooding were analyzed. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No Findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

(1 sample)

The inspectors reviewed the licensees program for maintenance, testing, and monitoring of risk significant heat exchangers (HXs) to assess the capability of the HXs to perform their design functions. The inspectors assessed whether the HX program conformed to Pilgrims commitments to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment. In addition, the inspectors evaluated whether any potential common cause heat sink performance problems could affect multiple HXs in mitigating systems or result in an initiating event. Based on risk significance and prior inspection history, the Reactor Building Closed Cooling Water system HXs were selected for review. 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

(1 sample)

The inspectors observed licensed operator requalification training on February 4, 2008.

Specifically, the inspectors observed simulator training on the Emergency Operating Procedures (EOPs) and Emergency Action Level (EAL) Classification and Notification.

The inspectors assessed the training to determine if the training adequately prepared the crew to determine EOP entry conditions and EAL classification levels. The inspectors reviewed the applicable training objectives to determine if they had been achieved. The inspectors also conducted a simulator fidelity review and comparison to the control room.

The inspectors verified that issues identified during the simulator session, and as part of the simulator fidelity review, were entered into the corrective action program. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

(1 sample)

The inspectors reviewed Entergy=s functional failure determination associated with CR-PNP-2008-00258, Unexpected APRM-D Half-Scram During Logic Test, conducted in accordance with Entergy procedures and the requirements of 10 CFR 50.65(a)(1) and (a)(2), ARequirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.@ The inspectors reviewed the Average Power Range Monitoring system maintenance rule functions, the basis for the conclusion that the issue was not considered a functional failure, and the potential for common cause and extent of condition.

Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

(6 samples)

The inspectors evaluated online maintenance risk assessments and licensee management of 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 due to out-of-service components. The inspectors verified the appropriate use of the licensees risk assessment tool, Equipment Out of Service (EOOS), and entry into appropriate risk categories. The inspectors evaluated whether Entergy 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 Entergy'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 scheduled and emergent maintenance risk assessments for the following maintenance and testing activities:

• Emergent work on A5 emergency bus voltage relays (Red);

• Halon testing in Cable Spreading Room (Yellow);

• Reactor Core Isolation Cooling system surveillance and P-140 surveillance (Yellow);

• High Pressure Coolant Injection system outage (Yellow);

• Station Blackout Diesel Generator and Shutdown Transformer unavailable for planned maintenance (Green); and

• Logic System Functional Testing of the A EDG with the Startup Transformer unavailable (Yellow).

b. Findings

Introduction.

The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.65(a)(4) for Entergy's failure to conduct an adequate risk assessment for emergent maintenance on the A5 Emergency Bus undervoltage (UV) relays. Specifically, the inspectors noted that Entergy had downgraded an on-line risk assessment from Red to Green, without a valid technical basis.

Description.

On January 11, 2008, Entergy discovered that the as-found set points on the 127-A5/1 and 127-A5/2 UV relays (which were in service on Emergency Bus A5 from May 2, 2005, to June 11, 2007), were out of the acceptable calibration range. Entergy subsequently determined the apparent cause to be an improper calibration method.

Entergy has submitted Licensee Event Report (LER)-08-002-00, Failure to Meet Technical Specification Requirement for Undervoltage Relay Trip Setting, to document the as-found condition.

Due to uncertainty regarding the calibration of the installed UV relays, on February 6, 2008, Entergy declared the A5 bus inoperable and unavailable. As a result, Entergy entered the Limiting Condition for Operation (LCO) for Technical Specification (TS) 3.2.B, Core and Containment Cooling Systems - Initiation & Control, which required that the system be repaired or the plant be placed in Cold Shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Entergy performed an emergent risk assessment and determined that the on-line risk condition was Red, the highest of four risk management categories (i.e., Green, Yellow, Orange, Red). Entergy initiated actions to remove and calibrate the UV relays using the correct calibration method. Upon removal of the UV relays and prior to recalibration and reinstallation, Entergy reassessed the risk condition of the plant to be Green. This assessment equated the condition to a monthly functional test conducted in accordance with PNPS Procedure 8.M.2-2.1.10, "4160 Volt Emergency Buses A5 and A6 Loss of Voltage and Degraded Voltage Relays," Attachment 1, Revision 34. Entergy subsequently found the relay set points to be within the acceptable range, reinstalled the relays, and exited the LCO.

The inspectors noted that the assessed configuration (i.e., comparison to the monthly surveillance) did not match the actual plant configuration. Specifically, during the surveillance, the UV relays remain installed and fuses are removed to simulate a UV condition on the bus, thereby initiating the protective function (i.e., tripping and blocking large motor loads, and allowing the EDG output breaker to close onto the A5 bus). Under the actual plant condition with the relays removed, this protective function is unavailable.

In addition, the ability to automatically close the EDG output breaker onto the bus is lost.

Entergy did not recognize that the EDG output breaker would not close with the relays removed, did not assess the EOOS risk of an unavailable EDG (Yellow), and, as a result, did not specify any risk management actions. The inspectors determined that, while the condition may not have warranted a Red risk condition, Entergy downgraded the risk assessment to Green without a thorough understanding of the plant condition and without an adequate technical basis.

Analysis.

The performance deficiency associated with this finding is that Entergy downgraded an emergent risk assessment from Red to Green without an adequate technical basis. In addition, Entergy did not recognize the loss of the EDG automatic function and did not specify any risk management actions. This finding is associated with the Mitigating Systems cornerstone and is more than minor because the risk assessment had incorrect assumptions that changed the outcome of the assessment. The inspectors conducted a screening in accordance with IMC 0609, Significance Determination Process, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. The finding was determined to be of very low safety significance (Green) because the Incremental Core Damage Probability Deficit for the timeframe that the relays were removed from service was significantly less than 1E-6. This finding has a cross-cutting aspect in the area of Human Performance, Decision Making, because Entergy did not use a systematic process to make a risk-significant decision, when faced with an unexpected plant condition. H.1(a)

Enforcement.

10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, states, in part, that ...the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities.

Contrary to the above, on February 6, 2008, Entergy failed to adequately assess the risk that resulted from removing A5 Emergency Bus UV relays. Specifically, Entergy downgraded an on-line risk assessment from Red to Green without a valid technical basis, did not recognize that the automatic EDG function would be lost, and did not specify risk management actions. Corrective actions taken for this violation included removing, calibrating, and reinstalling the affected relays; and subsequently determining the risk impact from the actual plant conditions with the subject relays removed. Additionally, Entergy will conduct briefings on the lessons learned from this issue, evaluate training needs, review the need to revise EOOS to include the UV relays, and evaluate changes to the risk assessment procedure. Because this violation was of very low safety significance and was entered into the licensees corrective action program (CR-PNP-2008-00946), this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000293/2008002-01, Inadequate Risk Assessment for Emergent Maintenance on A5 Emergency Bus Undervoltage Relays)

1R15 Operability Evaluations

a. Inspection Scope

(6 samples)

The inspectors reviewed six operability determinations associated with degraded or non-conforming conditions to determine if the operability determination was justified and if the mitigating systems or those affecting barrier integrity remained available such that no unrecognized increase in risk had occurred. The inspectors also reviewed compensatory measures to determine if the compensatory measures were in place and were appropriately controlled. The inspectors reviewed licensee performance against related TS and Updated Final Safety Analysis Report (UFSAR) requirements. The inspectors also reviewed CRs to determine whether Entergy was identifying and correcting deficiencies associated with operability evaluations. The inspectors reviewed the following degraded or non-conforming conditions:

• CR-PNP-2007-05089, Safety Relief Valve 3C;

• CR-PNP-2008-00187, Reactor Core Isolation Cooling system lube oil sample;

• CR-PNP-2008-00155, License Power Limit;

• CR-PNP-2008-00479, Salt Service Water Pump B blackened lugs on breaker;

• CR-PNP-2008-00595, Reactor Core Isolation Cooling system flow indicator moving during High Pressure Coolant Injection system operability flow test; and

• CR-PNP-2008-00617, Step jump in total core flow of approximately 1M lbm/hr on recorder DPR/FR-262-110.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

a. Inspection Scope

(1 sample)

The inspectors reviewed Temporary Modification EC0000004613, Raise Alarm Setting For SRV 203-3C from 200 DEG F to 230 DEG F on Tailpipe Temperature Recorder, and the associated 10 CFR 50.59 screening, to determine whether the licensing bases and performance capability of the associated risk significant system had been degraded through the modification. A walkdown was performed to determine whether equipment was installed in accordance with instructions. The inspectors reviewed applicable drawings and procedures to determine whether they properly reflected the temporary modifications. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

(4 samples)

The inspectors reviewed four samples of post-maintenance tests (PMT) during this inspection period. The inspectors reviewed these activities to determine whether the PMT adequately demonstrated that the safety-related function of the equipment was satisfied, given the scope of the work performed, and that operability of the system was restored. In addition, the inspectors evaluated the applicable test acceptance criteria to assess 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 their post-maintenance tests were evaluated:

• Control Rod Drive Pump B maintenance;

• A Salt Service Water Pump packing replacement;

• High Pressure Coolant Injection system maintenance outage; and

• A EDG Agastat replacement.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

(7 samples)

The inspectors reviewed seven samples of surveillance activities to determine whether the testing adequately demonstrated equipment operational readiness and the ability to perform the intended safety-related functions. The inspectors reviewed selected prerequisites and precautions to determine if they were met and if the tests were performed in accordance with the procedural steps. Additionally, the inspectors evaluated the applicable test acceptance criteria for consistency with associated design bases, licensing bases, and 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 surveillance tests were evaluated:

• Reactor Core Isolation Cooling system surveillance (IST);

• A EDG surveillance;

• A Residual Heat Removal Pump (IST);

• B Core Spray Pump (IST);

• Reactor Building Closed Cooling Water HX backwash;

• Reactor Coolant System (RCS) leakage detection surveillance; and

• B EDG surveillance.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

(1 simulator training sample and 1 drill observation sample)

The inspectors observed an evaluated licensed operator requalification simulator training exercise on February 4, 2008. The inspectors evaluated the operating crew activities relating to simulated activation of the emergency response organization, and accurate and timely classifications and notifications of EAL declarations. Additionally, the inspectors assessed the ability of training evaluators to adequately address operator performance deficiencies identified during the exercise. The inspectors also observed an emergency planning drill on March 6, 2008. The inspectors evaluated the emergency response organization performance in the simulator, the Technical Support Center, and the Emergency Operations Facility. The inspectors assessed the implementation of EAL classification and notification decisions. The inspectors also reviewed Pilgrims summary of drill observations and findings.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

(10 samples)

During the period January 7-10, 2008, the inspectors conducted the following activities to determine whether the licensee was properly implementing physical, administrative, and engineering controls for access to locked high radiation areas, and other radiologically controlled areas during power operations. Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, TS, and licensee procedures. This inspection activity represents the completion of ten samples relative to this inspection area.

Inspection Planning

The inspectors reviewed all licensee Performance Indicators (PIs) for the Occupational Radiation Safety Cornerstone for follow-up.

Plant Walkdown and Radiation Work Permits Reviews The inspectors identified exposure significant work areas and reviewed associated licensee controls, surveys, postings, and barricades for acceptability.

The inspectors toured accessible radiologically controlled areas and, with the assistance of a radiation protection technician, performed independent radiation surveys of selected areas to confirm the accuracy of survey data and the adequacy of postings.

Problem Identification and Resolution The inspectors reviewed the licensee=s self-assessments, audits, and Special Reports related to the access control program since the last inspection to determine if identified problems were entered into the corrective action program.

The inspectors reviewed six CRs related to access control to ensure follow-up actions were conducted in a timely and effective manner.

High Radiation Area and Very High Radiation Area Controls The inspectors discussed, with radiation protection technicians, supervision, and the radiation protection manager, the controls in place for areas that are or have the potential to become very high radiation areas during certain plant operations. The inspectors also discussed, with radiation protection supervision, the communication required with radiation protection prior to these operations to allow appropriate actions to properly post and control the radiation hazards.

The inspectors verified key controls and the integrity of several locked high radiation areas.

Radiation Worker and Radiation Protection Technician Performance Several radiologically related CRs were reviewed to evaluate if the incidents were caused by repetitive radiation worker errors and to determine if an observable pattern traceable to a similar cause was evident.

The inspectors observed radiation protection technician performance and questioned the technician regarding 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 January 7-10, 2008, the inspectors conducted the following activities to determine whether the licensee was properly implementing operational, engineering, and administrative controls to maintain personnel exposure ALARA for past activities performed in refueling outage (RFO)-16 and during routine plant operation.

Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, applicable industry standards, and licensee procedures. This inspection activity represents the completion of eight samples relative to this inspection area.

Inspection Planning The inspectors reviewed pertinent information regarding cumulative exposure history, current exposure trends, and ongoing activities to assess RFO-16 site ALARA performance and current exposure trends.

The inspectors reviewed the sites 3-year rolling average dose and compared the sites average with industrys average.

The inspectors verified that the licensees ALARA program procedure and the Radiation Work Permit procedure include job estimating and tracking.

Radiological Work Planning The inspectors evaluated departmental interfaces for any problems or missing program elements.

The inspectors reviewed several post job reviews to ensure lessons learned were entered into the corrective action program.

Source Term Reduction and Control The inspectors determined the status and historical trends of source terms. The addition of Noble Metals has decreased the amount of hydrogen injection. During the December, 2007, down-power to repair SRV-3B, the site experienced lower dose rates in the Drywell.

A new procedure is in progress to reduce the amount of cobalt in the reactor coolant system.

Radworker Performance The inspectors verified through discussions with radworkers that they demonstrate an ALARA philosophy.

Problem Identification and Resolution The inspectors reviewed audits and self-assessments for the ALARA program since January 2007, to determine whether identified problems were put in the corrective action program.

The inspectors reviewed elements of the licensee=s corrective action program related to implementing the ALARA program to determine if problems were being entered into the program for timely resolution. Ten condition reports related to dose/dose rate alarms, programmatic dose challenges, and the effectiveness in predicting and controlling worker dose were reviewed.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

[OA]

4OA1 Performance Indicator (PI) Verification

Barrier Integrity and Mitigating System Cornerstones

a. Inspection Scope

(3 samples)

The inspectors reviewed PI data to determine the accuracy and completeness of the reported data. The review was accomplished by comparing reported PI data to confirmatory plant records and data available in plant logs, the chemistry data base, LERs, CRs, and NRC inspection reports. The acceptance criteria used for the review were Nuclear Energy Institute (NEI) 99-02, Revision 5, "Regulatory Assessment Performance Indicator Guidelines," and Pilgrim TS 3.6, Primary System Boundary. Documents reviewed during the inspection are listed in the Attachment. The following performance indicators were reviewed:

$ Barrier Integrity Cornerstone, RCS Unidentified Leakage from the second quarter of 2007 through the fourth quarter of 2007;

$ Barrier Integrity Cornerstone, RCS Activity from the second quarter of 2007 through the first quarter 2008; and

$ Mitigating System Cornerstone, Safety System Functional Failures from the first quarter of 2007 through the fourth quarter 2007.

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

The inspectors performed a screening of each item entered into the licensee's corrective action program. This review was accomplished by reviewing the descriptions of each CR, attending daily screening meetings, and/or accessing the licensee's database. The purpose of this review was to identify conditions such as repetitive equipment failures or human performance issues that might warrant additional follow-up.

b. Findings

No findings of significance were identified.

.2 Annual Sample: Review of Valve Packing Failure

a. Inspection Scope

(1 sample)

The inspectors selected CR-PNP-2007-00949 for detailed review. The CR was written to determine the cause of a Reactor Water Cleanup valve packing failure that resulted in a plant shutdown. The inspectors reviewed the licensees root cause analysis, corrective actions, prioritization of corrective actions, and completion and effectiveness of corrective actions.

b. Findings and Observations

No findings of significance were identified. The inspectors determined that the licensee performed a thorough root cause analysis and developed and implemented timely corrective actions to prevent recurrence. The cause identified was the failure to provide specific procedural requirements for packing adjustments. Valve packing adjustments had been conducted using a skill-of-the-craft approach. Also, operating experience at other plants had been screened out, which was identified as a contributing cause. The immediate corrective action was to inspect, repack, or adjust the majority of valves in the drywell during RFO-16. A long term corrective action was established to develop a valve packing program using Entergy-wide and industry-wide experience and guidance.

Lessons learned from RFO-16 will be incorporated into this program. The inspectors determined that the causes and corrective actions were appropriate.

.3 Annual Sample: Mechanical Pressure Regulator (MPR) Reliability Concern

a.

Inspection Scope (1 sample)

The inspectors reviewed Entergy=s evaluation of performance issues associated with the main turbine Mechanical Pressure Regulator (MPR). Following the reactor trip on July 10, 2007, a MPR issue resulted in reactor pressure oscillations (approximately 10 psig swings) while operating on the bypass valves. Entergy performed troubleshooting, replaced a worn MPR pilot valve and bushing, and satisfactorily retested the MPR prior to plant restart in July 2007.

Subsequently, in August 2007, operators identified that they had to perform more frequent MPR adjustments to compensate for an apparent MPR setpoint drift.

The inspectors reviewed Entergy=s associated MPR troubleshooting, apparent cause evaluation (ACE), extent of condition review, and short and long-term corrective actions. The inspectors conducted several walkdowns of the MPR and the electrohydraulic pressure regulator controls and indications in the control room to assess material condition, operator awareness, and configuration control. The inspectors also interviewed plant personnel; inspected the worn MPR pilot valve and bushing; and reviewed procedures, related industry operating experience, and the vendor manual. In addition, the inspectors reviewed the Pilgrim TS and UFSAR to ensure that Entergy operated and maintained the MPR as required.

Documents reviewed are listed in the Attachment.

b. Findings and Observations

No findings of significance were identified.

Entergy developed and implemented a detailed MPR setpoint drift monitoring plan using their Operational Decision Making Issue (ODMI) process. Engineering adequately evaluated the degraded condition and identified appropriate trigger points, compensatory measures, and corrective actions. Engineering ensured that the associated ODMI plan was properly communicated to plant operators and maintained the guidance up to date.

The inspectors concluded that Entergy had taken timely and appropriate action in accordance with Pilgrim procedures, NRC Maintenance Rule requirements, and their corrective action program. The inspectors determined that engineering=s associated ACE was sufficiently thorough and based on the best available information, troubleshooting, sound engineering judgment, and relevant industry operating experience. In general, Entergy=s assigned corrective actions were aligned with the apparent causal factors, adequately tracked, appropriately documented, and completed as scheduled.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 Loss of 23kv line (1 sample)

a. Inspection Scope

At approximately 10:20 a.m., on January 9, 2008, the 23 kilo-Volt (kV) feeder line to the Shutdown Transformer was lost. The operators responded by implementing procedure 2.4.A.23, Loss/Degradation of 23 kV Line, Revision 10. Power was restored to the 23 kV line in approximately 30 minutes. The cause of the loss of the line was determined to be a branch contacting the line due to high winds in the area. The inspectors responded to the control room and confirmed that the control room was implementing actions to address the power loss. The inspectors also reviewed control room logs and operators compliance with applicable procedures.

b. Findings

No findings of significance were identified.

.2 Hydrogen Water Chemistry Transient

a. Inspection Scope

(1 sample)

On January 12, 2008, the in-service Hydrogen (H2) injection extended test system (ETS)flow controller failed resulting in an increased H2 injection into the feedwater system. The high H2 concentration caused Main Steam Line Radiation and Augmented Off Gas system alarms. Operators responded by checking local indications on the ETS and by securing the ETS per Procedure 10.2.4, Extended Test System Operating Procedure, Revision 39, and conducting troubleshooting to determine the cause of the failure. The operators responded to the Main Steam Line Radiation and Augmented Off Gas system alarms by implementing procedures 2.4.40, Rapid Increase in Main Steam Line or Off gas Activity and 2.4.141, Abnormal Recombiner Operation, respectively. The control room prepared for a power reduction (as specified in Procedure 2.4.141) with H2 concentrations exceeding 5 percent, but the H2 concentrations decreased below 5 percent (from actions taken to isolate ETS) before the power reduction was implemented. The inspectors subsequently reviewed operator logs, troubleshooting records and procedures implemented during this event.

b. Findings

No findings of significance were identified.

.3 Unplanned 24 Hour LCO Entry for Potential Loss of the A5 Emergency Bus UV Relays

a. Inspection Scope

(1 sample)

On February 6, 2008, operators declared the A5 emergency bus UV relays inoperable when they were unable to verify that the relays were properly calibrated prior to installation in June 2007. The previously installed relays, removed in June 2007, were found to be out of specification due to an improper calibration technique used prior to their installation in May 2005. The Operators entered TS 3.2.B, Core and Containment Cooling - Initiation and Control; TS 3.9.B, Auxiliary Electrical System, and TS 3.5.A, Core Spray and LPCI Systems. The most limiting of which, TS 3.2.B, required that the system be repaired or the plant placed in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Entergy subsequently removed the installed relays, verified that they were within the specified calibration range, reinstalled the relays, and performed functional testing satisfactorily; exiting the LCO. The inspectors reviewed control room logs and conducted interviews of operations staff to evaluate the adequacy of operator response to the emergent condition.

b. Findings

This issue was dispositioned in Section 1R13.

.4 Infrequently Performed Evolution: Vital Motor Generator (MG) Set Direct Current (DC)

Motor Shutdown for DC Motor Brush Replacement

a. Inspection Scope

(1 sample)

On February 27, 2008, Pilgrim operators performed a planned shutdown of the DC motor on the Vital MG set, with the plant at power. This infrequently performed evolution was conducted to permit replacement of the DC Motor Brushes. Although the deenergization of the DC motor was believed to be bumpless with the AC motor continuing to drive the AC generator, the evolution posed several potential challenges to Pilgrim operators because a perturbation in 4160 voltage could cause the transfer of the vital AC power from its normal to its alternate source which would cause a momentary interruption in vital AC power.

Similar evolutions in the past had resulted in complications such as the receipt of reactor building isolation signals, feed regulating valve position lock ups, and recirculation pump scoop tube position lock ups. Entergy revised an existing temporary procedure, TP06-025, Administrative Controls for Vital MG Set DC Motor Brush Replacement, for this evolution.

The procedure established several compensatory measures to mitigate the effects of a component malfunction or unexpected response. For instance, operators were briefed on Procedures 2.4.49, Feedwater Malfunctions, and 5.3.6 Loss of Vital AC (Y2). In preparation for the evolution, operators placed one feedwater flow control valve in manual.

Additionally, operators reduced power by approximately 25 MWt and locked the Recirculation MG set scoop tubes to preclude flow perturbations before the DC motor breaker was opened. The inspectors reviewed the procedure and observed the evolution from the control room to assess operator actions, command and control, and the adequacy of communications within the control room and between the control room and the field.

b. Findings

No findings of significance were identified.

.5 Operator Response to An Inoperable Start-Up Transformer Relay

a. Inspection Scope

(1 sample)

On March 10, 2008, operators determined that one of the start-up transformer degraded voltage relays was inoperable. Engineering and operations personnel met to discuss whether this affected the TS 3.2.B, Protective Instrumentation, Core and Containment Cooling Systems - Initiation and Control, Table 3.2.B, Start-Up Transformer Degraded Voltage, requirement of at least 2 operable channels. Operations initially declared the trip system inoperable and entered the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> shutdown action statement. Subsequently, engineering provided operations with information that showed the subject trip system remained operable with only one relay (out of four) inoperable. Operations declared the system operable and exited TS 3.2.B. The inspectors attended meetings between Operations and Engineering, reviewed TS, system drawings, and control room logs to assess Entergys response.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

On January 10, 2008, the radiation protection inspector presented the preliminary inspection results for the Access Control and ALARA Planning and Controls inspections to Mr. Kevin Bronson, Site Vice President, and other members of the Pilgrim staff. The inspector confirmed that no proprietary information was provided or examined during the inspection.

On April 8, 2008, the resident inspectors presented the preliminary inspection results to Mr. Robert Smith, General Manager Pilgrim Operations, and other members of the Pilgrim staff. The inspectors confirmed that no proprietary information was provided or examined during the inspection.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

S. Bethay Director, Nuclear Safety and Licensing

K. Bronson Site Vice President, Pilgrim

W. Coady ALARA Coordinator

W. Grieves QA Manager

J. Keyes Corrective Action & Assessment Manager

R. Larson Radiation Protection Technician

W. Lobo Licensing Engineer

J. Lynch Licensing Manager

W. Mauro Site, Radiation Protection Manager (Acting)

S. McAllister System Engineering Manager

A. Niederberger System Engineer (Turbine)

J. Norris ALARA Coordinator

D. Noyes Operations Manager

R. Smith General Manager Pilgrim Operations

J. Taormina Maintenance Manager

LIST OF ITEMS

Opened and Closed

05000293/2008002-01 NCV Inadequate Risk Assessment for Emergent Maintenance on A5 Emergency Bus Undervoltage Relays