IR 05000293/2008005

IR 05000293-08-005; on 10/01/2008 - 12/31/2008; Pilgrim Nuclear Power Station; Maintenance Risk Assessments and Emergent Work Control, and Event Followup

ML090370022
Person / Time
Site:	Pilgrim
Issue date:	02/05/2009
From:	David Lew Division Reactor Projects I
To:	Bronson K Entergy Nuclear Operations
Lew D
References
EA-09-013 IR-08-005
Download: ML090370022 (41)

Text

ary 5, 2009

SUBJECT:

PILGRIM NUCLEAR POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000293/2008005 - EXERCISE OF ENFORCEMENT DISCRETION

Dear Mr. Bronson:

On December 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 January 7, 2009, with you and members of your staff.

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

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

The report documents one NRC-identified finding, and one self-revealing finding of very low safety significance (Green). Both of these findings were determined to involve violations of NRC requirements. However, because of their very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCV)s, in accordance with Section VI.A.1 of the NRC's Enforcement Policy. If you contest the NCVs 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.

Additionally, this report closes one issue involving an incorrect entry into Technical Specification (TS) 4.0.3, Surveill ance Requirement Applicability, after you deter mined Reactor Protection System (RPS) time response testing had not been conducted on several RPS scram contactors in 2007 (Unresolved Item (URI) 05000293/2007-003-04). The NRC determined that TS 3.1, Reactor Protective System, should have been entered vice entering TS 4.0.3, because the surveillance on this portion of the RPS system had never been performed. Although the incorrect entry into TS 4.0.3 is a violation of NRC requirements, the NRC identified no performance deficiency and that discretion is warranted because: (1) licensee current basis

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 documents do not specifically clarify the distinction between a missed surv eillance and one that has never been performed, (2) the licensee subsequently completed the surveillance testing satisfactorily, and (3) the issue was of very low safety significance. Based on these facts, I have been authorized, after consultation with the Director, Office of Enforcement, and the Region I

Regional Administrator, to exercise enforcem ent discretion in accordance with Section VII.B.6 of the Enforcement Policy, and refrain from issuing enforcement action for the violation.

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 ins pection 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/ Original Signed By; David C. Lew, Director Division of Reactor Projects

Docket No. 50-293 License No. DPR-35

Enclosure: Inspection Report 05000293/2008005 w/Attachment: Supplemental Information

cc w/encl:

Vice President, Operations, 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 R. Walker, 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

SUMMARY OF FINDINGS

IR 05000293/2008-005; 10/01/2008-12/31/2008; Pilgrim Nuclear Power Station; Maintenance

Risk Assessments and Emergent Work Control, and Event Followup

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

Two Green findings, both of which were non-cited violations (NCVs), 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" (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 a risk assessment for emergent maintenance on the High Pressure Coolant Injection (HPCI) system injection valve. Specifically, the failure to conduct a risk assessment resulted in Entergy not recognizing an increase in risk to a Yellow condition, and therefore no risk management actions were taken.

Entergy entered this issue into their corrective action program. Corrective actions will include revising attachments in Entergy's Technical Specification requirements procedure to perform a risk review as a result of emergent maintenance activities.

This finding was more than minor because Entergy failed to consider the unavailability of a risk significant system where the outcome of the risk assessment would have been a change in a risk management category. The inspectors conducted an evaluation 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 timefram e that HPCI was removed from service was significantly less than 1E-6. The inspectors determined that this finding had 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)

Green.

A self-revealing Green non-cited violation (NCV) of TS 5.4.1, "Procedures", was identified for a procedure which resulted in an inadvertent isolation of the Reactor Core Isolation Cooling (RCIC) system. Specifically, the procedure was previously revised and a step was inadvertently placed out-of-order. The procedure incorrectly instructed technicians to remove relay contact blockers, or "boots", before clearing an isolation signal which resulted in the system isolation. Entergy entered this issue into their corrective action program. Corrective actions will include revising this procedure and reviewing other surveillance procedures that had been revised at the same time.

This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone. Isolating the RCIC system affected the cornerstone objective of ensuring the availability of sy stems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated this finding using IMC 0609.04, "Phase 1 - Initial Screening and Characterization of Findings". This finding was of very low safety significance because it was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of a single train system for greater than the Technical Specification allowed outage time, and was not made risk-significant because of external events. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Resources, because Entergy did not ensure that the procedure was complete and accurate. H.2(c) (Section 4OA3)

B. Licensee-Identified Violations

None.

REPORT DETAILS

===Summary of Plant Status

Pilgrim Nuclear Power Station (PNPS) operated at or near 100 percent power during the majority of the inspection period. However, on December 19, 2008, Entergy scrammed from 100 percent power due to a load reject during a winter storm. Entergy resumed 100 percent power operation on December 24, 2008. The plant remained at or near 100 percent for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Seasonal Susceptibility

a. Inspection Scope

(1 sample)===

===The inspectors reviewed actions taken by the licensee in preparation for the onset of cold weather during the week of November 2, 2008. The inspectors reviewed Procedure 8.C.40, Seasonal Weather Surveillance, and verifi ed that select ed steps had been completed. The inspectors walked down selected areas addressed in the procedure to determine if heat tracing as well as plant heating systems were properly working. The inspectors also walked down exterior portions of the Condensate Storage Tanks and the Station Blackout Diesel. The documents reviewed during the inspection are listed in the

.

b. Findings

No findings of significance were identified.

.2 Impending Storm

a. Inspection Scope

(1 sample)===

On December 19, 2008, a significant winter storm was tracking to impact the Pilgrim

===plant that afternoon and into the evening. The inspectors reviewed Entergy's preparations for the impending snow storm as well as for the high winds expected to accompany the storm. The inspectors reviewed Entergy's severe weather procedures including coastal storm preparations and operations during severe weather (specifically, snow storm preparations). The inspectors also reviewed the stated plant risk given the external risk increase and compared this to equipment that was out of service to determine if there was an overall increase in risk. The inspectors conducted a tour of the plant grounds and the switchyard to determine if loose debris or other material could become airborne in the presence of high winds or if there were any vulnerabilities to snow accumulation (such as emergency diesel generator ventilation), and thereby impact to safety related equipment. The documents reviewed during the inspection are listed in 6 Enclosure the Attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

Partial System Walkdowns (71111.04Q)

a. Inspection Scope

(5 samples)===

===The inspectors performed five 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:

• Instrument and Service Air Systems During Maintenance on K-111 Air Compressor;

• Automatic Depressurization System with Reactor Core Isolation Cooling unavailable due to maintenance;

• "B" Spent Fuel Pool System while in standby;

• "A" train Salt Service Water (SSW) System with "D" SSW unavailable; and

• "B" Core Spray System with High Pressure Coolant Injection out for maintenance.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

Fire Protection - Tours (71111.05Q)

a. Inspection Scope

(5 samples)===

===The inspectors performed walkdowns of five 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.

The documents reviewed during the inspection are listed in the Attachment. The fire 7 Enclosure protection areas reviewed were:

$ Reactor Building/El.23'-0" up to El.51'-0", East Side - Fire Area 1.9, Fire Zone 1.9; $ "A" Switchgear and Load Center Room - Fire Area 1.9, Fire Zone 2.2;

$ "B" Switchgear and Load Center Room - Fire Area 1.10, Fire Zone 2.1;

$ Spent Fuel Pool Cooling Pumps and Heat Exchanger Area - Fire Area 1.9, Fire Zone 1.13; and

$ Vital Motor Generator Set Room - Fire Area 1.9, Fire Zone 3.5.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Licensee-Administered Annual Operating Tests

a. Inspection Scope

(1 sample)===

On November 17, 2008, a region-based inspector conducted an in-office review of

===results of the licensee-administered annual operating tests and comprehensive written exams for 2008. The inspection assessed whether pass rates were consistent with the guidance of NRC Manual Chapter 0609, Appendix I, "Operator Requalification Human Performance Significance Determination Process." The inspector verified that:

• Crew failure rate was less than 20 percent. (Crew failure rate was 0 percent)

• Individual failure rate on the dynamic simulator test was less than or equal to 20 percent. (Individual failure rate was 0 percent)

• Individual failure rate on the walk-through test was less than or equal to 20 percent. (Individual failure rate was 0 percent)

• Individual failure rate on the comprehensive written exam was less than or equal to 20 percent. (Individual failure rate was 0 percent)

• Overall pass rate among individuals for all portions of the exam was greater than or equal to 75 percent. (Overall pass rate was 100 percent)

b. Findings

No findings of significance were identified.

.2 Licensed Operator Training

a. Inspection Scope

(1 sample)===

The inspectors observed licensed operator training on November 18, 2008. Specifically,

===the inspectors observed classroom Senior Reactor Operator (SRO) training on the 8 Enclosure Severe Accident Guidelines (SAGs), Core Mitigation Strategies, and the Emergency Operating Procedures (EOP). The lectures discussed SAG and EOP entry conditions, roles and responsibilities for the SROs, and the phenomenology of severe accidents. The inspectors assessed the training to determine if the training adequately prepared the SROs to determine what actions to take in a severe accident situation and when to enter the SAGs. The inspectors reviewed the lesson plans and applicable training objectives to determine if they had been achieved. The documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Review of Functional Failures

a. Inspection Scope

(3 samples)===

The inspectors reviewed three functional failure determinations conducted in accordance

===with Entergy procedures and the requirements of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. The inspectors reviewed the system maintenance rule functions, the basis for the conclusion that the issues were considered functional failures, and the potential for common cause and extent of condition. The inspectors also reviewed data to verify whether or not the functional failures resulted in placing the systems in (a)(1). The inspectors reviewed system health reports to determine if actions taken were reasonable and appropriate. In addition, the inspectors reviewed Entergy's condition reports and corrective actions. The documents reviewed during the inspection are listed in the Attachment. The functional failure determinations reviewed were:

• CR-PNP-2008-02120, Post Accident Sample System has inadequate heat tracing;

• CR-PNP-2008-02469, Standby Gas Treatment System root valve does not fully shut; and

• CR-PNP-2008-03338, High Pressure Coolant Injection Valve relay in circuit breaker cabinet fails.

b. Findings

No findings of significance were identified.

.2 Review of K-117 Air Compressor (a)(1) Action Plan

a. Inspection Scope

(1 sample)===

The inspectors reviewed the (a)(1) corrective action plan for the K-117 air compressor

===unavailability exceeding the (a)(2) unavailability criteria for it ems such as:

(1) appropriate work practices;

(2) identifying and addressing common cause failures;

(3) scoping in accordance with 10 CFR 50.65(b) of the maintenance rule (MR);

(4) characterizing reliability issues for perform ance;

(5) trending key parameters for c ondition monitoring;

(6) charging unavailability for performance;

(7) classification and reclassification in 9 Enclosure accordance with 10 CFR 50.65(a)(1) or (a)(2); and

(8) appropriateness of performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2)and/or appropriateness and adequacy of goals and corrective actions for SSCs/functions classified as (a)(1). The documents reviewed during the inspection are listed in the

.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

(3 samples)===

The inspectors evaluated three online maintenance risk assessments for planned and

===emergent maintenance activities. The inspectors reviewed maintenance risk evaluations, work schedules, and control room logs to determine if concurrent maintenance or surveillance activities adversely affect ed the plant risk already incurred with out-of-service components. The inspectors verified the appropriate use of Entergy's 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, minimized the probability of initiating events, and ma intained the functional capability of mitigating systems. The inspectors assessed Entergy's risk management actions during plant walkdowns. The documents reviewed during the inspection are listed in the Attachment. The inspectors reviewed the conduct and adequacy of maintenance risk assessments for the following maintenance and testing activities:

$ Yellow Risk, During Reactor Core Isolation Cooling and Air Compressor K-111 Maintenance and Testing Activities;

$ Emergent Risk of Inoperability of the High Pressure Cool ant Injection and Reactor Core Isolation Cooling Systems; and

$ Forced Outage Shutdown Risk Assessments.

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 a risk assessment for emergent maintenance on the High Pressure Coolant Injection (HPCI) system injection valve. Specifically, the failure to conduct a risk assessment resulted in Entergy not recognizing an increase in risk to a Yellow condition, and therefore no risk management actions were taken.

Description.

At 7:44 p.m. on October 21, 2008, operators received an alarm in the control room and determined the cause was a loss of control power for a HPCI injection valve. Entergy declared HPCI inoperable and entered the Limiting Condition for Operation (LCO) for Technical Specification (TS) 3.5.C.2, "HPCI System." This LCO requires that the system be made operable within 14 days, otherwise be in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

With HPCI unavailable, risk management actions are generally taken to protect those systems that provide redundancy for its function, such as the Reactor Core Isolation 10 Enclosure Cooling system. Entergy did not conduct a risk assessment nor recognize the plant risk condition was "Yellow" and therefore did not take any risk management actions. Entergy

restored HPCI operability and exited the LCO ei ght hours later.

Analysis.

The performance deficiency associated with this finding is that Entergy did not perform a review of the increased risk while HPCI was inoperable and, as a result, did not take risk management actions as required by 10 CFR 50.65(a)(4). This finding is associated with the human performance attribute of the Mitigating Systems cornerstone

and is more than minor because Entergy failed to consider the unavailability of a risk significant system where the outcome of the risk assessment would have been a change in risk management category. The inspectors conducted an evaluation 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 HPCI was removed from service was significantly less than 1E-6.

The inspectors determined that this finding had 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, from October 21, 2008 to October 22, 2008, Entergy failed to assess the increased risk that resulted from HPCI unavailability.

As a result, Entergy did not recognize a "Yellow" risk condition and did not take any risk management actions. Corrective actions will include revising attachments in Entergy's Technical Specification requirements procedure to perform a risk review as a result of emergent maintenance activities. Because this violation was of very low safety significance (Green) and was entered into the licensee's corrective action program (CR-PNP-2008-

===03792), this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000293/2008005-01, Failure to Conduct a Risk Assessment for Emergent Maintenance on the High Pressure Coolant Injection System)

=

The inspectors reviewed five operability determi nations 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 Technical Specification and UFSAR requirements. The documents reviewed during the inspection are listed in the Attachment. The inspectors reviewed the following degraded or non-conforming conditions:

$ CR-PNP-2008-03049, Air Void in High Pressure Coolant Injection (HPCI) Suction Line; $ CR-PNP-2008-03015, HPCI Cabling In-Service Aging Needs to be reviewed;

$ CR-PNP-2008-03404, Shutdown Transformer Breaker (A802) won't close remotely from the Control Room;

$ CR-PNP-2007-04801, Restriction Orifices Missing from Recirculation Pump Instrument Lines; and

$ CR-PNP-2008-03611, Thermography identifies a hot spot in Air Cooled Breaker (ACB) 104.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

.1 Permanent Modification

a. Inspection Scope

(1 sample)===

The inspectors reviewed Permanent Modification ERO2115031, "Change Orientation of

===PSV-8008", and the associated 10 CFR 50.59 screening, to determine whether the licensing bases and performance capability of the associated system had been degraded through the modification. A walkdown of the "A" Residual Heat Removal Heat Exchanger was performed to determine if the PSV-8008 valve's new orientation would be subject to additional stress or be impacted by other adverse conditions. The inspectors reviewed system drawings to determine whether they reflected the permanent modification. The documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Temporary Modification

a. Inspection Scope

(1 sample)===

The inspectors reviewed Temporary Modification Engineering Change (EC) 7768,

==="Temp. Mod. Required to Document Heat Detection System Disabled on Pre-Action Sprinkler System for the Turbine Bearings", to determine whether the performance capability of the Fire Protection System had been degraded th rough the modification. The inspectors reviewed the Updated Fire Hazards Analysis, procedures, and the 10 CFR 50.59 screening to ensure the temporary modification did not adversely affect fire protection program attributes. The inspectors reviewed control room drawings to determine whether they properly reflected the temporary modification. The documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

12 Enclosure

1R19 Post-Maintenance Testing

a. Inspection Scope

(6 samples)===

The inspectors reviewed six 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 verify 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. The documents reviewed during the inspection are listed in the Attachment. The following maintenance activities and their post-maintenance tests were evaluated:

$ Reactor Core Isolation Cooling Outboard Isolation Valve Electrical Maintenance;

$ Open and Inspect Residual Heat Removal (RHR) Pump Discharge Check Valve 1001-67A;

$ Replace Undervoltage Relay for High Pressure Coolant Injection Pump Injection Valve MO-2301-08;

$ "A" RHR Motor Operated Valve Preventive Maintenance and Breaker, Diagnostic, and Relay Testing for MO-1001-23A, MO-1001-16A, MO-1001-7A, MO-1001-34A, MO-1001-18A, MO-1001-37A, MO-1001-36A and RHR Pump "A" Relays;

$ Overhaul of Salt Service Water Pump 208D; and

$ Replace Current Transformers on the F-15 Substation Feeding the Shutdown Transformer.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

(1 sample)===

The inspectors reviewed the outage plan and shutdown risk assessments for a forced,

===non-refueling outage conducted from December 19, 2008, through December 23, 2008.

The outage was conducted following a plant transient due to a load reject and subsequent reactor plant scram. The load reject was the result of a significant fault in a switchyard breaker during a severe winter storm. During this outage, the inspectors observed plant shutdown activities including the outage activities listed below. The documents reviewed during the inspection are listed in the Attachment.

• Hot Shutdown Control

• Shutdown Risk Assessment and Risk Management

• Implementation of TS

• Outage Control Center Activities

• Plant Startup

• Licensee identification and resolution of problems identified during and related to outage activities

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

(2 samples)===

The inspectors reviewed two 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. The documents reviewed during the inspection are listed in the Attachment.

The following surveillance tests were evaluated:

$ Standby Liquid Control In-Service Testing (IST); and

$ "B" Emergency Diesel Gener ator Operability Testing.

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

(1 sample)===

During the period of October 20 through 23, 2008, 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, and other radiologically controlled areas (RCA) during power operations. Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, relevant Technical Specifications, and the licensee

=s procedures. This inspection activity represents the completion of one

(1) sample relative to this inspection area.

Plant Walkdown and Radiation Work Permits (RWP) Reviews The inspectors examined Pilgrim's physical and programmatic controls for highly activated or contaminated materials (non-fuel) stored within the spent fuel pool. The inspectors toured the spent fuel pool area and reviewed the procedure for handling highly radioactive objects. The inspectors also toured the Traversing Incore Probe (TIP)

Room and Torus Room areas. The inspectors observed the postings and barricades in each area and reviewed surveys and RWPs for the areas including the electronic 14 Enclosure personal dosimeter alarm set points (both integrated dose and dose rate) for conformity with survey indications and plant policy.

b. Findings

No findings of significance were identified. 2OS2 As Low As Reasonably Achievable (ALARA) Planning and Controls (71121.02)

a. Inspection Scope

(5 samples)===

During the period October 20 through 23, 2008, the inspector conducted the following

===activities to verify that the licensee was properly implementing operational, engineering, and administrative controls to maintain personnel exposure ALARA during routine plant operation. Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, applicable industry standards, and the licensee

=s procedures. This represents the completion of five samples relative to this inspection area.

Inspection Planning

The inspectors requested a list of the work activities ranked by actual exposure that were completed during refueling outage (RFO) 16. The inspectors reviewed the RWP and ALARA documentation for the five highest dose jobs for RFO16. The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors reviewed the exposure estimates and compared the estimates with the actual dose received.

Radiation Worker Performance The inspectors observed radiation worker performance prior to entering the RCA. The inspectors questioned workers relative to their individual and department dose goals and their understanding of the previous day's goals and the actual dose received.

Declared Pregnant Workers

The inspectors requested exposure results and monitoring controls employed for declared pregnant workers with respect to the requirements of 10 CFR 20. There were no declared pregnant workers since January 1, 2008.

b. Findings

No findings of significance were identified. 2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

a. Inspection Scope

(1 sample)===

During the period of October 20 through 23, 2008, the inspectors conducted the following

===activities to evaluate the adequacy of the licensee's program to maintain Self Contained Breathing Apparatus (SCBA). This inspection activity represents the completion of one 15sample relative to this inspection area.

Self-Contained Breathing Apparatus (SCBA) Maintenance and User Training

The inspectors reviewed the status and surveillance records of SCBA staged and ready for use in the plant. The inspectors observed the inspection of SCBA in the control room and compared the records with the actual equipment staged for use. The inspectors verified that control room operators and other emergency response personnel are trained.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

[OA]

4OA1 Performance Indicator (PI) Verification

.1 Mitigating Systems

a. Inspection Scope

(2 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, CRs, System Health Reports, and NRC inspection reports. The acceptance criteria used for the review was Nuclear Energy Institute (NEI) 99-02, Revision 5, "Regulatory Assessment Performance Indicator Guidelines." Documents reviewed during the inspection are listed in the Attachment.

The following performance indicators were reviewed:

• Emergency Diesel Generators (EDG) from the fourth quarter 2007, through the third quarter of 2008; and

• Cooling Water (Salt Service Water/RBCCW) from the fourth quarter 2007, through the third quarter of 2008.

b. Findings

No findings of significance were identified.

.2 Occupational Exposure Control Effectiveness

a. Inspection Scope

(1 sample)===

The inspectors reviewed implementation of the licensee

====s Occupational Exposure Control Effectiveness Performance Indicator (PI) Program. Specifically, the inspector reviewed recent ACTION reports, and associated documents, for occurrences involving locked high radiation areas, very high radiation areas, and unplanned exposures against the criteria specified in Nuclear Energy Institute (NEI) 99-02, Revision 5, "Regulatory 16Assessment Performance Indicator Guidelines," to verify that all occurrences that met the NEI criteria were identified and reported as performance indicators. This inspection activity represents the completion of one sample relative to this inspection area; completing the annual inspection requirement.

b. Findings

No findings of significance were identified.

.3 RETS/ODCM Radiological Effluent Occurrences

a. Inspection Scope

(1 sample)===

The inspectors reviewed relevant effluent release reports for the period of January 1,

===2007, through December 31, 2007, for issues related to the public radiation safety performance indicator, which measures radiological effluent release occurrences that exceed 1.5 millirem / quarter whole body or 5.0 millirem / quarter organ dose for liquid effluents; 5 millirads / quarte r gamma air dose, 10 millirads

/ quarter beta air dose, and 7.5 millirads / quarter for organ dose for gaseous effluents. This inspection activity represents the completion of one sample relative to this inspection area; completing the annual inspection requirement.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered into the Corrective Action Program (CAP)

a. Inspection Scope

The inspectors performed a screening of each item entered into the licensee's CAP.

This review was accomplished by reviewing printouts 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: Operator Workarounds

a. Inspection Scope

(1 sample)===

The inspectors performed the annual review of operator workarounds to verify Entergy

===17was identifying operator workaround problems at an appropriate threshold and entering them into the corrective action program. The inspectors reviewed identified workarounds to determine whether the mitigating system function was affected, whether the operator's ability to implement abnormal and emergency operating procedures was affected, and whether appropriate procedures had been updated to reflect actual plant conditions. The inspection was accomplished through personnel interviews, plant tours, and review of station documents. The documents reviewed during the inspection are listed in the

.

b. Findings and Observations

No findings of significance were identified. Operator workarounds have been identified and entered into the corrective action program for resolution. No unrecognized impacts to operator or system performance were identified, and corrective actions have been implemented to restore the affected systems.

.3 Annual Sample: Safety Relief Valve Leakage

a. Inspection Scope

(1 sample)===

The inspectors selected the issue of Safety Relief Valve (SRV) leakage as an inspection

===sample for in-depth review because of recent forced plant shutdowns due to SRV leakage. Additionally, SRV leakage has been a long-standing issue at Pilgrim Nuclear Power Station (PNPS). This inspection was conducted to determine if Entergy was taking appropriate corrective actions to address SRV leakage.

The inspectors reviewed procedures, condition reports, engineering evaluations, root cause analyses, and interviewed plant personnel to assess Entergy's problem identification, evaluation, and corrective action effectiveness with respect to SRV leakage. Additionally, the inspectors reviewed the Technical Specifications and Updated Final Safety Analysis Report to assess the adverse impact of SRV leakage with respect to design basis requirements. The documents reviewed during this inspection are listed in the Attachment.

b. Findings and Observations

No findings of significance were identified.

Pilgrim Nuclear Power Station (PNPS) Safety Relief Valves are of the two-stage Target Rock-type design, consisting of a pilot-stage assembly and a main-stage assembly.

Industry Operating Experience has shown that two-stage Target Rock SRVs exhibit some amount of pilot-stage leakage during plant operation. Additionally, industry operating experience has quantified SRV leakage in terms of SRV tailpipe temperature, as well as an upward setpoint drift impact. PNPS Technical Specifications require that an engineering evaluation be performed to justify continued operation with elevated tailpipe temperatures. On a number of such occasions, Entergy has implemented an Operational Decision Making Issue (ODMI) to establish administrative limits for the maximum allowable SRV tailpipe temperature for continued plant operation. The 18operating limits were established to maintain SRV setpoint drift within the +/-1% tolerance required by Technical Specifications.

SRV pilot-stage leakage has challenged PNPS throughout the plant's operating history.

Entergy has been forced to shutdown the plant from full power operation on three occasions. On each occasion, SRV tailpipe temperatures approached the administrative limits imposed in the respective ODMIs for March 2004, December 2007, and April 2008.

Following the March 2004 shutdown, the leaking valves were removed from service and a root cause analysis was performed as a result of high, as-found setpoint testing results.

The root cause was determined to be corrosion bonding of the pilot valve disc/seat, with a contributing cause of insulation deficiencies. The contributing cause determination stated that proper fitting SRV insulation is critical for Target Rock SRVs, to reduce the propensity of leakage and eliminate the conditions conducive to corrosion binding.

Corrective actions included refurbishing the pilot valve discs, as well as SRV insulation enhancements. The December 2007 shutdown also identified inadequate SRV fitting insulation as one of the root causes for the SRV leakage (CR-PNP-2007-04936). The inspector noted Entergy has self-identified deficiencies with SRV insulation dating back to 1993.

The December 2007, and April 2008, shutdowns identified inadequate simmer margin as one of the root causes (CR-PNP-2007-04936) for SRV pilot-stage leakage. Simmer margin is defined as the pressure difference between SRV setpoint and plant normal operating pressure. At PNPS, the plant simmer margin is limited by a +/-1% Technical Specification tolerance (i.e., margin) for the allowable SRV setpoint. PNPS transient and accident analyses have shown this tolerance is required to maintain peak reactor vessel pressures within the code allowable limits. The inspector noted Entergy has self-identified insufficient simmer margin in a number of condition reports dating back to 2004. Additionally, General Electric has issued Service Information Letters to highlight the relationship between pilot-stage leakage and plant operating simmer margin. At the time of this inspection, Pilgrim was investigating corrective action options to address simmer margin, as documented in CR-PNP-2007-04936. The options being pursued included contracting with vendors to increase plant simmer margin via analysis and/or modifications, and completing an independent root cause analysis of pilot valve disc/seat leakage. Entergy was also pursuing the option for development of a new pilot valve disc/seat design.

At PNPS, the effects of SRV upward setpoint drift, even due to small amounts of leakage, are magnified by the limited SRV setpoint tolerance allowed by TS due to the designed plant relief capacity. The inspector found Entergy's planned corrective actions, to address the contributing elements of SRV leakage, to be appropriate.

19.4 Annual Sample: Review of Aggregate Impact of Significant Events Which Had Occurred During 2007

a. Inspection Scope

(1 sample)===

The inspectors selected CR-PNP-2007-04865 for detailed review. The CR was written in December 2007, to evaluate whether there were any additional insights or trends to be

===identified from an aggregate review of significant events which had occurred during 2007.

The inspectors reviewed the licensee's analysis and recommendations for corrective actions. The documents reviewed during the inspection are listed in the Attachment.

b. Findings and Observations

No findings of significance were identified. Entergy reviewed significant events which occurred during 2007, and categorized the events as to their root and contributing causes, whether any regulatory findings had been issued, their impact on plant operation, and the aggregate impact on plant performance (i.e., equipment or human performance). Entergy determined that several of the issues related to the performance of the Emergency Diesel Generators (EDG) and conducted a separate analysis of these events. TI-176 has been conducted to evaluate current EDG testing, the results of which are documented in Section 4OA5. Entergy also reviewed the remaining events and determined that, in some cases, expanding the scope of the evaluation of a given event or condition to review other systems or programs would have been appropriate. As a result, Entergy has instituted a corrective action for the Operations Department to include, as part of their review of degraded condition operability, t he need to consider other systems or components that may have a similar vulnerability to t he degraded condition. In addition, Entergy will be conducting training with Engineering Department staff to similarly consider other systems, programs, or components when evaluating degraded conditions for extent of condition and corrective actions.

The inspectors reviewed Entergy's corrective actions and evaluated more recent issues to determine if Entergy applied the principles discussed above. The inspectors noted instances where both Operations Department and Engineering Department staffs evaluated a given issue for its applicability beyond the condition itself and, as a result, specified additional corrective actions. The inspectors concluded that these initiatives should improve Entergy's effectiveness in evaluating and correcting issues and in identifying other areas for improvement that may not have been previously considered.

.5 Semi-Annual Review to Identify Trends

a. Inspection Scope

(1 sample)===

The inspectors performed a review of Entergy's Corrective Action Program (CAP) and

===associated documents to identify trends that could indicate the existence of a more significant safety issue. The review was focused on repetitive equipment and corrective maintenance issues, but also considered the results of daily inspector CAP item screening.

The review included issues documented in CAP trend reports and the site CAP performance indicator data. The review focused on the six month period of July 2008, through December

===202008, although the inspectors also evaluated previous trend results for CRs from June 2007, through June 2008, which were discussed in NRC Inspection Reports 05000293/2008003 and 05000293/2007005. Documents reviewed during the inspection are listed in the attachment.

b. Findings and Observations

No findings of significance were identified. In NRC Inspection Report 05000293/2008003, the inspectors concluded that corrective actions to improve configuration control at Pilgrim had not been in effect long enough to conclude whether they were effective. As a result, the configuration control low level trend originally initiated in the fourth quarter report of 2007, continued to be monitored during the past two quarters. The inspectors noted that Entergy's corrective actions appear to have been effective in reducing the number of mispositioning errors. Corrective actions have included conducting operator fundamental training on precise plant control and human performance, generating lessons learned, and generating a standard for mispositioned components and a fleet procedure on configuration control.

In addition to the corrective actions discussed in NRC Inspection Report 05000293/2008003, the Operations department instituted a Mentorship Pilot Program to augment additional reactor operators to assist non-licensed operators in their professional development.

Entergy has focused their program in the areas of operator fundamentals, human performance, shift turnover, preparation for shift activities, and operator engagement during briefings. Corrective actions undertaken by the Operations Department appear to have improved the performance of configuration control and, as a result, this low level trend is considered closed. No additional low level trends were identified which would indicate the presence of a broader safety issue.

=

On the evening of October 6, 2008, operators inadvertently isolated the RCIC system while performing Surveillance Procedure 8.M.2-2.6.3, RCIC Steam Line High Temperature Instrument Functional Test. Specifically, "boots" which were installed to block applicable relays were removed before auto-isolation trip signals had cleared. The RCIC system isolated due to a Group 5 signal which closed the inboard and outboard steam supply valves, which resulted in the actuation of the turbine trip throttle valve. The Group 5 isolation was reset and the operators placed the RCIC system back in its standby lineup.

The inspectors reviewed operator logs, applicable procedural requirements, and technical specifications. The documents reviewed during the inspection are listed in the

.

b. Findings

See Section 4OA3.5.

.2 Entergy Response to a Fire in the Health Physics Calibration Laboratory

a. Inspection Scope

(1 sample)===

On October 29, 2008, a fire occurred in the Health Physics (HP) instrumentation

===calibration laboratory located in the Operations and Maintenance (O&M) building.

Following the start of the electric fire pump and the generation of O&M building smoke alarms, the on-site Fire Brigade identified that a fire had occurred in the HP calibration lab and that the fire suppression system had actuated and extinguished the fire.

Operators requested off-site assistance from the Plymouth Fire Department and both organizations entered the room to verify that the fire suppression system had extinguished the fire. In addition, Entergy declared an Unusual Event due to the occurrence of a fire in the protected area for which off-site assistance was requested.

The inspectors responded to the site to evaluate Entergy's actions in response to the fire and to assess any impact on the licensed radiological materials located in the HP calibration laboratory. The inspectors reviewed Entergy's immediate actions to respond to the fire, root cause investigation, event timeline, and corrective actions. The documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.3 Operator Response to Unpl

anned Reactor Core Isolation C ooling (RCIC) Unavailability

a. Inspection Scope

(1 sample)===

On October 22, 2008, operators determined that the RCIC flow controller was inoperable

===due to aged power supply capacitors. The industry recommended service life is 7 to 10 years and the RCIC capacitors had been in service from 21 to 30 years. Operations declared RCIC inoperable and entered TS 3.5.D, "Reactor Core Isolation Cooling (RCIC)

System", a 14-day shutdown action statement. The control panel flow controller was replaced with the flow controller from the alternate shutdown panel (ASP) and operations entered TS 3.12, "Fire Protection" due to the inoperable ASP. During post-installation testing, the flow controller from the ASP was not able to maintain rated flow at the required pressure. A refurbished controller intended to replace the one from the ASP was then installed in the control panel. This flow controller was able to achieve and maintain rated pressure and flow. Operations then declared the system operable and exited TS 3.5.D. Entergy initiated a 10 CFR 50.72, 8-hour, non-emergency notification report for a condition that could have prevented the fulfillment of the safety function of a mitigating system. Entergy conducted subsequent bench testing of the aged capacitors from November 6, 2008 to November 8, 2008 and determined that these capacitors would have been able to perform their function in the required mission time. As a result, Entergy retracted their 10 CFR 50.72 report on December 9, 2008. The inspectors 22reviewed Technical Specifications, control room logs, interviewed operations and engineering personnel, and reviewed the basis for the retraction of the 10 CFR 50.72 report. The documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.4 Unplanned High Pressure Coolant Injection (HPCI) Isolation

a. Inspection Scope

(1 sample)===

On the afternoon of November 20, 2008, operators inadvertently isolated the HPCI

===system while performing surveillance procedure 8.M.2-2.5.3, Attachment 1, HPCI High Steam Line Temperature. Specifically, in-series, high temperature relays were both inadvertently opened causing a Group 4 isolation signal. A Group 4 isolation signal closes both the inboard and outboard steam supply valves, which rendered the HPCI system inoperable. The Group 4 isolation was reset and the operators placed the HPCI system back in its standby lineup using Procedure 2.2.21, High Pressure Coolant Injection. The inspectors reviewed operator logs, applicable procedural requirements, and Technical Specifications. The documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.5 Reactor Scram on Load Reject from failure of 345 KV Switchyard Circuit Breakers 104

and 105

a. Inspection Scope

(1 sample)===

On December 19, 2008, operators responded to a reactor scram from 100% reactor

===power due to a load reject from the main generator. During a coastal winter storm, an electrical fault developed on the transformer side of circuit breakers 104 and 105 (flashover of the ACB-105 "A" phase generator bushing resulted in a significant current to ground fault) resulting in the main transformer differential relay, main transformer overcurrent relay, and main transformer distance relay actuations to open breakers 104 and 105. Without circuit breakers 104 and 105 to route power to the electrical grid, the turbine, and hence, the reactor scrammed due to a main turbine trip initiated by a main generator load reject. As a result of the reactor scram and load reject, three of four safety relief valves opened briefly, which is expected for the condition. Entergy also received a Group Two isolation signal for Secondary Containment and a Group Six isolation signal for Reactor Water Cleanup. Both of these isolation signals were expected for the situation. However, Y3 and Y4, two of Pilgrim's 120 VAC safety related instrument buses, remained de-energized following the trip, an unexpected response.

Y3 and Y4 are 120 VAC electrical buses which power mitigating system instrumentation including containment isolation logic, SRV acoustic monitoring, and other safety related 23equipment. This issue was investigated and corrected prior to startup. In addition, a 10 CFR 50.72 notification was generated due to the valid actuation of the Reactor Protection System. The inspectors responded to the control room, reviewed reactor plant parameters and operator response to this event. The documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.6 Loss of Start-Up Transformer Power Supply from 345KV Switchyard Circuit Breakers

ACB 102 and 103

a. Inspection Scope

(1 sample)===

On December 20, 2008, operators responded to a momentary loss of the 345 KV power

===supply from the ACB 102 and 103 switchyard circuit breakers. This resulted in the loss of buses A1 through A6 and their associated loads. The emergency diesel generators responded as designed to provide power to vital buses A5 and A6. Group Isolations 1, 2 and 6 were generated on the Reactor Protection Systems signal (Main Steam Isolation Valves (MSIV) closed, primary sample valves isolated, Reactor Water Clean Up isolated and the Reactor Building Ventilation system isolated). The Reactor Core Isolation Cooling and High Pressure Coolant Injection Systems were operated in manual to maintain reactor vessel level and pressure. ACB 102 and 103 re-closed and Buses A1 through A4 were recovered and Buses A5 and A6 were restored to the Start-Up Transformer power supply. MSIV's were opened and Group Isolation Signals were reset.

The licensee generated a 10 CFR 50.72 8-hour report to the Nuclear Regulatory Commission discussing this event. The inspectors responded to the control room, reviewed reactor plant parameters and operator response to this event. The documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.7 (Closed) LER 05000293/2008-003-00, Reactor Core Isolation Cooling (RCIC) System

Declared Inoperable During Surveillance Te sting due to Procedure Error

a. Inspection Scope

(1 sample)===

The inspectors evaluated LER 05000293/2008-003-00, "RCIC System Declared

Inoperable during Surveillance Testing Due to Procedure Error". This LER is closed with a finding.

b. Findings

Introduction.

A self-revealing Green non-cited violation (NCV) of TS 5.4.1, "Procedures", was identified for a procedure error which resulted in an inadvertent isolation of the 24Reactor Core Isolation Cooling (RCIC) system. Specifically, the procedure was previously revised and a step was inadvertently placed out-of-order which resulted in the isolation of RCIC.

Description.

On the evening of October 6, 2008, Entergy inadvertently isolated the RCIC system while performing Surveillance Procedure 8.M.2-2.6.3, "RCIC Steam Line High Temperature Instrument Functional Test". When performing this surveillance, Instrumentation and Controls (I&C) technicians use "boots" to block relay contacts and prevent closure of the RCIC steam supply line isolation valves. The I&C technicians followed the procedure, which incorrectly instructed them to remove the "boots" before clearing the auto-isolation trip signals that would close the valves. This resulted in a Group 5 isolation signal that isolated the RCIC system by closing the inboard and outboard steam supply valves, actuating the RCIC turbine trip throttle valve, and rendering the RCIC system inoperable. The operators reset the Group 5 isolation and placed the RCIC system back in its standby lineup within one hour.

The licensee had previously revised several surveillance procedures for the RCIC system and the High Pressure Coolant Injection (HPCI) System. During the revision to Procedure 8.M.2-2.6.3, the step to remove the "boots" was placed before the step to

clear the auto-isolation signal. Corrective actions will include revising this procedure and reviewing other procedures that had been revised at the same time.

Analysis.

The performance deficiency associated with this finding was that Entergy introduced an error into a procedure during revision that resulted in an inadvertent isolation of the RCIC system. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone. Isolating the RCIC system affected the cornerstone objective to ensure the availability of systems t hat respond to initiating ev ents to prev ent undesirable consequences. The inspectors evaluated this finding using IMC 0609.04, "Phase 1 -

Initial Screening and Characterization of Findings". This finding was of very low safety significance because it was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of a single train system for greater than the TS allowed outage time, and was not made risk-significant because of external events.

The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Resources, because Entergy did not ensure that the procedure was complete and accurate. H.2(c)

Enforcement.

Technical Specification 5.4.1, "Procedures", requires that written procedures be maintained as recommended in NRC Regulatory Guide (RG) 1.33, "Quality Assurance Program Requirements," Revision 2, Appendix A, February 1978.

RG 1.33, Appendix A, Se ction 8 includes procedures for surveillance tests. Contrary to this, Procedure 8.M.2-2.6.3 was not adequately maintained, because it included an error

that resulted in an isolation of the RCIC system. Corrective actions will include revising this procedure and reviewing other surveillance procedures that had been revi sed at the same time. Because this finding is of very low safety significance and Entergy has entered it into their corrective action program (CR-PNP-2008-03182), this violation is 25being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000293/2008005-02, Procedural Error Resulting in Unplanned RCIC Isolation)

4OA5 Other Activities

1. (Closed) URI 05000293/2007003-04 Application of TS 4.0.3 When It Was Discovered That a Surveillance Had Never Been Performed On June 25, 2007, Entergy informed the Nuclear Regulatory Commission (NRC) staff that it had missed a Technical Specification (TS) surveillance requirement to perform time response testing of four Reactor Protection System (RPS) scram contactors. During their review, Entergy identified that the four RPS scram contactors had never been tested. Entergy evaluated the operability of the RPS system and det ermined t hat the system remained operable and that TS 4.0.3, "Surveillance Requirement Applicability," would allow a delay period up to the limit of the specified surveillance frequency. The

inspectors questioned Entergy regarding the applicability of TS 4.0.3 given that the time response test had never been performed on the RPS scram contactors, as compared to missing a surveillance test following satisfactory initial system baseline testing that originally showed system operability. As a result of this implementation of TS 4.0.3, Entergy failed to take action in accordance with TS 3.1, "Reactor Protective System,"

which constituted a violation of NRC requirements. Entergy later modified the applicable surveillance procedures and successfully response time tested all RPS scram contactors.

In Task Interface Agreement (TIA) 2008-004, the NRC staff disagreed with Entergy on its implementation of TS 4.0.3 and considered Entergy to have been in violation of TS 3.1, "Reactor Protection System," as a result. Discretion is warranted because:

(1) licensee current basis documents do not specifically clarify the distinction between a missed surveillance and one that has never been performed,

(2) the licensee subsequently completed the surveillance testing satisfactorily, and

(3) the issue was of very low safety significance, since when the correct testing was accomplished, it was completed satisfactorily indicating that the timing of the reactor scram function was not negatively impacted. Accordingly, the NRC staff is exercising enforcement discretion for the TS 3.1 violation in accordance with Section VII.B.6 of the NRC Enforcement Policy and no violation will be issued. Enforcement Action (EA)09-013, Failure to Enter TS 3.1 When a Surveillance Requirement Was Not Met. URI 05000293/2007003-04 is closed.

2. Implementation of Temporary Instruction (TI) 2515/176 - Emergency Diesel Generator Technical Specification Surveillance Requirements Regarding Endurance and Margin Testing

a. Inspection Scope

The objective of TI 2515/176, "Emergency Diesel Generator Technical Specification Surveillance Requirements Regarding Endurance and Margin Testing," was to gather information to assess the adequacy of nuclear power plant emergency diesel generator 26(EDG) endurance and margin testing as prescribed in plant-specific technical specifications (TS). The inspectors reviewed emergency diesel generator ratings, design basis event load calculations, surveillance testing require ments, and emergency diesel generator vendor's specifications and gathered information in accordance with TI 2515/176. The inspector assessment and information gathered while completing this TI was discussed with licensee personnel. This information was forwarded on to the Office of Nuclear Reactor Regulation for further review and evaluation.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

On September 11, 2008, the inspectors presented the preliminary inspection results of a Problem Identification and Resolution sample to Mr. B. Sullivan, Nucl ear Engineering Director, Mr. S. Bethay, Safety Assessment Director, and other members of the Entergy staff. Following additional in-office review, the inspectors conducted a final exit meeting via teleconference on December 16, 2008, with Mr. S. Bethay and other members of Entergy staff. The inspectors verified that no proprietary information is documented in this report.

On October 23, 2008 at 9:30 A.M., the Occupational Radiation Safety exit meeting was held by phone with Mr. Joe Lynch, Licensing Manager.

On October 31, 2008, an exit meeting of the results of Temporary Instruction (TI)2515/176 was conducted. The preliminary inspection results were presented to Mr. Stan Wollman, Engineering Supervisor, and other members of the Pilgrim staff. The inspector confirmed that no proprietary information was provided or examined during the inspection.

On January 7, 2009, the resident inspectors conducted an exit meeting and presented the preliminary inspection results to Mr. Kevin Bronson, Site Vice President, 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

K. Bronson Site Vice President

R. Smith General Manager Pilgrim Operations

S. Bethay Director, Nuclear Safety Assurance

B. Sullivan Dire

ctor, E ngineering W. Cody ALARA Technician

J. Lamoureux Sr. Project Manager

W. Lobo Licensing Engineer

J. Lynch Licensing Manager

W. Mauro Supervisor, Radiological Engineering

C. Minott Sr. Project Manager

D. Noyes Operations Manager

R. O'Neill Operations Outage Manager S. Paul Operations Supervisor

J. Priest Radiation Protection Manager

M. Santiago Supervisor, Operations Training

T. Trainor Outage Manager

LIST OF ITEMS

Opened and Closed

09-013 EA Failure to Enter TS 3.1 When a Surveill

ance Requirement Was Not Met

05000293/2008-005-01 NCV Failure to Conduct a Risk Assessment for Emergent

Maintenance on the High Pressure Coolant Injection System

05000293/2008-005-02 NCV Procedural Error Resulting in Unplanned RCIC Isolation

Closed

05000293/2008-003-00 LER RCIC System Decl

ared Inoperable During Surveillance Testing Due to Procedure Error

05000293/2007-003-04 URI Application of TS 4.0.3 When it is Discovered that a Surveillance Has Never Been Performed