IR 05000271/2011002

Lr 05000271-11-002;01/01/2011 - 03/31/2011; Vermont Yankee Nuclear Power Station; Post-Maintenance Testing; Event Follow-up

ML111190386
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	04/29/2011
From:	Diane Jackson NRC/RGN-I/DRP/PB5
To:	Michael Colomb Entergy Nuclear Operations
Jackson, D E RI/DRP/PB5/610-337-5306
References
IR-11-002
Download: ML111190386 (34)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENDALE ROAD

SUBJECT:

VERMONT YANKEE NUCLEAR POWER STATION - NRC INTEGRATED I NSPECTION REPORT 0500027 1 1201 1002

Dear Mr. Colomb:

On March 31,2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Vermont Yankee Nuclear Power Station. The enclosed inspection report documents the inspection results, which were discussed on April 1 1,2011, with you and other members of your statf.

The inspection examined activities performed 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 two self-revealing findings of very low safety significance (Green).

These iindings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they have been entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCV),

consisient with Section 2.3.2.a of the NRC's Enforcement Policy. lf you contest any NCV, 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; witfr copies to the RegionalAdministrator, Region l; the Director, Office oi Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001: and the NRC Senior Resident Inspector at Vermont Yankee. In addition, if you disagree with any cross-cutting aspects assigned to the findings in this report, you should provide a responie within 30 days of the date of this inspection report, with the basis for your disagreement, to the RegionalAdministrator, Region l, and the NRC Senior Resident lnspector at Vermont Yankee. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web Site at http://www,nrc.qov/readinq-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

&A Donald E. Jackso Projects Branch 5 Division of Reactor Projects Docket No. 50-271 License No. DPR-28

Enclosure:

Inspection Report No. 0500027 1 12011002 M Attachment: Supplemental Information

REGION I Docket No.: 50-271 License No.: DPR-28 Report No.: 0500027112011002 Licensee: Entergy Nuclear Operations, Inc.

Facility: Vermont Yankee Nuclear Power Station Location: Vernon, Vermont 05354-9766 Dates: January 1,2011 through March 31,2011 Inspectors: D. Spindler, sr. Resident lnspector, Division of Reactor Projects (DRP)

S. Rich, Resident InsPector, DRP Approved by: Donald E. Jackson, Chief Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

lR 0500027112011002;0110112011 - 0313112011; Vermont Yankee Nuclear Power Station;

Post-Maintenance Testing; Event Follow-up.

This report covered a three-month period of inspection by resident inspector staff and region-based inspectors. Two Green, self-revealing findings, which were determined to be non-cited violations (NCV), were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using lnspection Manual Chapter (lMC) 0609, "Significance Determination Process." The cross-cutting aspects for the findings were determined using IMC 0310, "Components Within The Cross-Cutting Areas." Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

.

Green.

A self-revealing, non-cited violation (NCV) of very low safety significance (Green) of Technical Specifications 6.4, "Procedures," was identified for inadequate implementation of Entergy procedure EN-MA-118, "Foreign Material Exclusion," Revision 6, which resulted in foreign material intrusion into the Residual Heat Removal Service Water (RHRSW) system.

Specifically, Entergy did not establish a Foreign Material Exclusion (FME) Zone l around the open RHRSW system between completing the closeout inspection and system closure following pump replacement. Entergy's immediate corrective actions included conducting a "stand down," reinforcing the standards and requirements for FME controls and general procedural compliance, as well as reinforcing expectations for the attention to detail of work practices. Entergy entered the issue into their corrective action program to evaluate for additional corrective measures.

The inspectors determined that the finding was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences, (i.e., core damage). Specifically, foreign material made its way into the'A'Residual Heat Removal Heat Exchanger (RHR HX) and rendered the'A' RHRSW train inoperable for several days. A review of NRC lnspection Manual Chapter (lMC) 0612, Appendix E, "Minor Examples," revealed that no minor examples were applicable to this finding. The inspectors used IMC 0609.04, "Phase 1 of Findings," and determined that the finding- Initial Screening and Characterization 'A'

required a Phase 2 review because the RHRSW train had an actual loss of safety function for greater than its allowed outage time (7 days). This finding was assessed using IMC 0609 and was determined to be of very low safety significance (Green) based on a Phase 2 analysis. The finding had a cross-cutting aspect in the Human Performance cross-cutting area, Work Practices component, because Entergy personnel did not follow EN-MA-1 18. Specifically, they did not establish a FME Zone 1 after the system closeout inspection.

tH.4(b)l (Section 1 R1 e)

.

Green.

A self-revealing, Green NCV of Technical Specification 6.4, "Procedures," was identified in which maintenance and planning personnel did not involve engineering personnel as required by Entergy procedure EN-MA-101 , "Fundamentals of Maintenance," Revision 9, and EN-WM-105, "Planning," Revision 8, resulting in the incorrect material being used to replace the gasket on the flange of High Pressure Coolant Injection System (HPCI)steam trap 23T-3. Entergy ultimately replaced the gasket with the correct material and entered this issue into their corrective action program.

The inspectors determined that the finding was more than minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance (Green) in accordance with IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations," using Significance Determination Process (SDP) Phases 1,2 and 3. A Region I Senior Reactor Analyst (SRA)conducted a Phase 3 analysis because the Phase 2 analysis indicated that the finding had the potential to be greater than very low safety significance (Greater than Green). This finding had a cross-cutting aspect in the Human Performance cross-cutting area, Decision Making component, because Vermont Yankee personnel did not obtain interdisciplinary input on the decision to use a different, incorrect gasket material in a steam trap in the HPCI system. H.1(a) (Section 4OA3)

Other Findings

Violations of very low safety significance that were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summarv of Plant Status Vermont Yankee (W) Nuclear Power Station began the inspection period operating at 100 percent power. On February 14,2011, W performed a planned power reduction to 58 percent power to perform main steam line isolation valve testing, main turbine stop valve testing, and a rod pattern adjustment. W returned to 100 percent power on February 15,2011, and remained at or near 100 percent power for the duration of the inspection period.

1. REACTORSAFETY

Cornerstones: Initiating Events, M itigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

.1 lFpendinq Adverse Weather

a.

lnspection Scope (1 sample)

The inspectors reviewed Entergy's procedures in order to evaluate the process for implementation of extreme cold temperature preparedness. This review was conducted from January 21, 2011, through January 24,2011, due to forecasted overnight low temperatures below negative 15 degrees Fahrenheit. The inspectors reviewed adverse weather information contained in Vermont Yankee's lndividual Plant Examination for External Events and compared it to the actions specified in Entergy operating procedure (OP) 3127, "Natural Phenomena," Revision 26 and OP 2196, "Seasonal Preparedness,"

Revision 31. The inspectors reviewed documents, interyiewed personnel and performed a walkdown of the reactor building, turbine building and intake structure to verify that actions required by the above procedures had been taken and that indoor temperatures were not low enough to impact equipment operability.

b.

Findinqs No findings were identified.

,2 External Floodino Readiness a.

Inspection Scope (1 sample)

The inspectors reviewed Entergy's flood protection barriers and procedures for coping with externalflooding. The inspectors reviewed externalflooding information contained in the Updated Final Safety Analysis Report (UFSAR) and lndividual Plant Examination for External Events, and compared it to the actions specified in OP 3127, "Natural Phenomena," Revision 26. The inspectors performed walkdowns of the switchgear rooms, cooling towers, intake structure, and outside areas. They also examined the equipment specified in the OP (sump pumps, floor drain plugs, sandbags, etc.) to determine if it was available for use. The inspectors also reviewed a sample of external flooding-related conditions identified in W's CAP to determine if they were appropriately identified and corrected. The documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

1R04 Equipment Alionment

.1 Partial Equipment Aliqnment (7 1111.04O)

a. Inspection Scope

(5 samples)

The inspectors performed five partial system walkdowns to verify correct system alignment, and to identify any discrepancies that could impact system operability.

Observed plant conditions were compared to the standby alignment of equipment specified in applicable piping and instrumentation drawings, and operating procedures.

The inspectors verified valve positions and the general condition of selected components. Finally, the inspectors evaluated material condition, housekeeping, and component labeling. The documents reviewed are listed in the Attachment. The following systems were inspected:

.

Core Spray with 'A' Residual Heat Removal (RHR) Train Unavailable;

.

Remote Shutdown Systems;

.

'B' Emergency Diesel Generator with 'A' Service Water Train Unavailable;

.

Automatic Depressurization System during High Pressure Coolant Injection System Testing; and

.

'A' RHR Service Water Train with 'B'Train Unavailable.

b. Findinqs No findings were identified.

,2 Complete Equipment Aliqnment (7 1 111.04S)

a. Inspection Scope

(1 sample)

The inspectors performed a complete equipment alignment inspection of the safety-related portion of the 4 kilovolt (kV) electrical distribution system. The inspectors compared the actual system configuration to approved drawings, the UFSAR, and operating procedures. Through a system walkdown, the inspectors evaluated whether the switchgear rooms were properly ventilated, Direct Current (DC) control power was available, associated transformers were free of leaks and other degraded conditions, and deficiencies had been entered into the corrective action program. The inspectors also assessed housekeeping and component labeling. ln addition, the inspectors reviewed the system health reports, and evaluated a sample of previously identified deficiencies to determine if they had been properly addressed. The inspectors performed a search of the corrective action program for equipment alignment problems to verify that Entergy was identifying problems at an appropriate threshold and resolving them appropriately. These activities constituted one complete equipment alignment inspection sample. Documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

1R05 Fire Protection

Quarterlv lnspection (7 1111

.05 O)

a. Inspection Scope

(5 samples)

The inspectors performed inspections of five fire areas based on a review of the Vermont Yankee Safe Shutdown Capability Analysis and the Fire Hazards

Analysis.

The inspectors reviewed Entergy's fire protection program to determine the specified fire protection design features, fire area boundaries, and combustible loading requirements for the selected areas. The inspectors verified, consistent with applicable administrative procedures, that combustibles and ignition sources were adequately controlled; passive fire barriers, manualfire-fighting equipment, and detection and suppression equipment were appropriately maintained; and compensatory measures for out-of-service, degraded, or inoperable fire protection equipment were implemented in accordance with Entergy's fire protection program. The inspectors evaluated the fire protection program for conformance with the requirements of License Condition 3.F. The documents reviewed are listed in the Attachment. The following fire areas were inspected:

.

Turbine Lube OilTank and Storage Room, FZ-6;

.

Control Building E\.262'Cable Vault, FA ASD, FZ-2;

.

HPCI Room, FZRB-2;

.

'B'EDG Room with Barrier Breach, FA-9; and

.

Main, Auxiliary and Startup Transformers.

b. Findinos No findings were identified.

1R06 Flood Protection Measures (71111.06 - 1 sample)

lnternal Floodino Inspection Scope The inspectors reviewed Entergy's flood protection design and barriers for coping with internalflooding on the Reactor Building 252' elevation. The inspectors reviewed internalflooding information contained in Vermont Yankee's lndividual Plant Examination for External Events (IPEEE) and the internalflooding design basis document. The inspectors performed a walkdown of the area to ensure equipment and structures needed to mitigate an internalflooding event were as described in the IPEEE and the design basis document. Additionally, the inspectors reviewed CRs related to internal flooding to ensure identified problems were properly addressed for resolution.

Documents reviewed are listed in the Attachment. These activities constituted one internal flood protection measures inspection sample.

b.

Findinqs No findings were identified.

1R1 1 Licensed Operator Requalification Proqram (71111.11)

Quarterlv Inspection (71111.1 1O)

Inspection Scope (1 sample)

The inspectors observed a simulator-based licensed operator requalification (LOR)exam on February 7,2011. The inspectors assessed the performance of risk significant operator actions, including the use of emergency operating procedures. The inspectors evaluated crew performance in the areas of clarity and formality of communications; ability to take timely actions; prioritization, interpretation, and verification of alarms; procedure usage; control board manipulations; and command and control. The inspectors also compared the simulator configuration with the actual control board configuration. Finally, the inspectors verified that evaluators were identifying and documenting crew performance problems. The documents reviewed are listed in the

.

b.

Findinqs No findings were identified.

1R12 Maintenance Effectiveness (7111 1.12)

Quarterly Inspection (7 1 1 1 1

.124 )

a. Inspection Scope

(3 samples)

The inspectors reviewed performance-based problems involving selected in-scope structures, systems and components (SSCs) to assess the effectiveness of the maintenance program. The reviews focused on the following aspects when applicable:

.

Proper Maintenance Rule scoping in accordance with 10 CFR 50.65; o Characterization of reliability issues;

.

Charging system and component unavailability;

.

10 CFR 50.65 paragraph (aX1) and (a)(2) classifications;

.

ldentifying and addressing common cause failures;

.

Appropriateness of performance criteria for SSCs classified paragraph (aX2); anO

.

Adequacy of goals and corrective actions for SSCs classified paragraph (aX1).

The inspectors reviewed the applicable system health reports, maintenance backlogs, and Maintenance Rule basis documents. The documents reviewed are listed in the

. The following structures, systems and components were inspected:

.

Augmented Off-gas System;

.

Instrument Air System; and o Service Air System.

b. Findinqs No findings were identified.

1 R13 Maintenance Risk Assessments and Emeroent Work Control (71111

.13 )

a. Inspection Scope

(5 samples)

The inspectors evaluated five maintenance risk assessments for planned and emergent maintenance activities to verify that the appropriate risk assessments were performed prior to removing equipment for work. The inspectors reviewed maintenance risk evaluations, maintenance plans, work schedules, and control room logs to determine if concurrent or emergent maintenance or surveillance activities significantly increased the plant risk. The inspectors reviewed risk assessments to determine if they were performed as required by 10 CFR 50.65 paragraph (aX4) and implemented in accordance with Entergy's administrative procedure (AP) 0172, "Work Schedule Risk Management - Online." When emergent work was performed, the inspectors observed activities to determine if plant risk was promptly reassessed and managed. The inspectors conducted plant walkdowns to verify that appropriate risk management actions had been taken. The documents reviewed are listed in the Attachment. The following maintenance activities were inspected:

.

Work Week 1101 - Emergent Work on 'A' RHRSW and RHR Trains;

.

Work Week 1103 -'B' Diesel Generator Testing and Battery B-AS-2 Maintenance;

.

Work Week 1105 - Service Water Valve testing;

.

Work Week 1107 - Emergent Work on HPCI; and

.

Work Week 1111 - Service Water Strainer maintenance and Standby Liquid Control Surveillance.

b. Findinqs See Section 4OA7.

1R15 Operabilitv Evaluations

a. Inspection Scope

(5 samples)

The inspectors reviewed five operability evaluations associated with degraded or non-conforming conditions to assess the acceptability of the evaluations, the use and control of applicable compensatory measures, and compliance with Technical Specifications.

The inspectors reviewed and compared the technical adequacy of the evaluations with the Technical Specifications, UFSAR, associated design basis documents, and Entergy's procedure EN-OP-104, "Operability Determinations." The documents reviewed are listed in the Attachment. The inspectors reviewed evaluations of the following degraded or non-conforming conditions:

.

CR 2011-00301 -'B' RHRSW Pump Met In-service Testing Action Limit for Low Pump Differential Pressure;

.

CR 2011-00694 - Main Diesel Fuel Oil Flash Point at Procedural Lower Limit;

.

CR 2011-00876 and 2011-00880 - Water Leakage Found on Cylinder Adapter Plates on 'B' Emergency Diesel Generator (DG-1-B) ;

.

CR 2011-00773 - RCIC Environmental Qualification (EQ); anO

.

CR-2010-0556, 2010-05023,2011-00193, 2011-00652, and 2011-00713 - General Electric Hitachi Design Life of 'D' and 'S' Lattice Marathon Control Rod Blades.

b. Findinos No findings were identified.

1R18 Plant Modifications

Permanent Plant Modifications

a. Inspection Scope

(2 samples)

The inspectors reviewed EC21288, "Replace V76-38 with a New Check Valve," and EClT444, "ChemicalTreatment Connections to the Spent Fuel Cooling (SFPC)

System," to ensure that they did not adversely affect the availability, reliability, or functional capability of any risk-significant SSCs. The inspectors reviewed the engineering change packages, and observed the systems in operation following the implementation of the modifications. The documents reviewed are listed in the

.

b. Findinqs No findings were identified.

1R19 Post-Maintenance Testinq

Inspection Scooe (7 samples)

The inspectors reviewed seven post-maintenance test (PMT) activities on risk-significant systems. The inspectors reviewed these activities to determine whether test acceptance criteria were clear and consistent with design basis documents. When testing was directly observed, the inspectors determined whether installed test equipment was appropriate and controlled, and whether the test was performed in accordance with 10 CFR Part 50, Appendix B, Criterion Xl, "Test Control," and applicable station procedures. Upon completion, the inspectors performed a walkdown to verify that equipment was returned to the proper alignment necessary to perform its safety function, and evaluated whether conditions adverse to quality were entered into the CAP for resolution. The documents reviewed are listed in the Attachment. The inspectors reviewed the PMTs performed for the following maintenance activities:

r RHR Pumps'A'and 'C'and RHR Service Water Pump 'A'Testing Following RHR Heat Exchanger Work; e Fire Protection Check Valve V76-3B Replacement; o 'B' Service Water Pump Replacement;

.

'B' Emergency Diesel Generator Overhaul; o Repair of HPCI Steam Trap 23T-3;

.

'C'Circulating Water Pump Replacement; and

.

'B'RHR Service Water Pump Replacement.

b. Findinqs

Introduction:

A self-revealing, NCV of very low safety significance (Green) of Technical Specifications 6.4, "Procedures," was identified for inadequate implementation of Entergy procedure EN-MA-1 18, "Foreign Material Exclusion," Revision 6, which resulted in foreign material intrusion into the RHRSW system. Specifically, Entergy did not estabfish a procedurally required FME Zone l around the open RHRSW system between completing the closeout inspection and system closure following pump replacement.

Discussion: On December 27,2010, Entergy began removal of the 'C' RHRSW pump for a planned replacement. During the planned replacement of the 'C' RHRSW pump, the 'A'train of RHRSW was planned to remain in an operable status, since the'A' RHRSW pump was not planned to be affected by the 'C' pump replacement, and since one RHRSW pump provides sufficient capacity to perform the safety function of the 'A' RHRSW train. During the work activity, the area was controlled as a FME Zone 2, which requires some FME boundaries and work practices, but does not require material entering the zone to be either tracked on a log or tied down as is required in a FME Zone 1 . On December 30, 2010, Entergy personnel performed a closeout inspection of the

'C' RHRSW pump and piping prior to final pump assembly, but did not upgrade the area to a FME Zone 1. EN-MA-118, "Foreign Material Exclusion," states that a FME Zone 1 should be established, "when a final visual inspection of internal cleanliness before system closure is not possible." During the final steps of pump assembly, Entergy personnel used a number of cloth FME covers to prevent nuts and washers from falling into the open piping. Because the area was not designated a FME Zone 1, the cloth covers were not tied down or logged as FME zone inventory, and one cover was left behind in the system after the pump was completely installed. During post-maintenance testing on December 30, 2010, Entergy observed that the pump did not meet the flow rate acceptance criterion that is required for operability. On January 2,2011, the newly installed pump was removed for internal inspection, and a cloth FME cover was found lodged in the pump. Part of the cover had been torn away during the pump run and cariied further into the RHRSW system. Subsequent system inspection identified a large piece of the cover on the 'A' Residual Heat Removal Heat Exchanger (RHR HX)baffle plate and small pieces in other areas of the 'A' RHRSW train. Discovery of this material in the'A'RHR HX rendered the entire RHRSW'A'train inoperable as of December 30, when the unacceptable flow rate was first discovered. Entergy subsequently removed all of the foreign materialfrom the 'A' RHRSW train. On January 7, 2011, Entergy successfully tested the 'A' RHRSW train and returned it to service. The

'C' RHRSW pump was successfully tested and returned to service on January 8, 2011.

This issue was entered into Vermont Yankee's corrective action program. Shortly after retrieval of the FME cover, Entergy conducted a "stand down" to discuss the event and reinforce FME control standards. lmmediate corrective actions included conducting a "stand down," reinforcing the standards and requirements for FME controls and general procedural compliance, as well as reinforcing expectations for the attention to detail of work practices. Additionally, Entergy entered the deficiency into their corrective action program to evaluate for additional corrective measures.

Analvsis: The performance deficiency was that Entergy did not fully implement written procedures, as required by Technical Specification 6.4 and Entergy procedure EN-MA-118, covering preventive and corrective maintenance operations which could have an effect on the safety of the reactor. Specifically, Entergy performed the closeout inspection prior to RHRSW system closure, and did not establish a FME Zone l during the remaining work activities prior to system closure. This issue was within Entergy's ability to foresee and correct and should have been prevented. This led to foreign material intrusion into the'A'train of RHRSW, rendering the'A'train inoperable.

Traditional Enforcement did not apply; as the issue did not have actual or potential safety consequences, had no willful aspects, nor did it impact the NRC's ability to perform its regulatory function. A review of NRC IMC 0612, Appendix E, "Minor Examples," revealed that no minor examples were applicable to this finding. The inspectors determined that the finding was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences, (i.e., core damage). Specifically, materialfrom the FME cover made its way into the 'A' RHR HX and rendered the'A' RHRSW train inoperable for greater than 7 days. A review of NRC IMC 0612, Appendix E, "Minor Examples," revealed that no minor examples were applicable to this finding.

The inspectors used IMC 0609.04, "Phase 1 - InitialScreening and Characterization of Findings," and determined that the finding required a Phase 2 review because the'A' RHRSW train had an actual loss of safety function for greater than its allowed outage time (7 days). Using IMC 0609 Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations," and an event likelihood of 3-30 days, the inspectors determined that the finding was of very low safety significance (Green). The most dominant core damage sequence was a transient without the power conversion system (TPCS): TPCS(1) + cHR(2) + CV(3) = 6 (Green). The risk was mitigated by the unaffected 'B' RHR heat exchanger and by the containment vent' The finding had a cross-cutting aspect in the Human Performance cross-cutting area, Work Practices component, because Entergy personnel did not follow procedure EN-MA-118. Specifically, Entergy failed to establish a FME Zone 1 after the system closeout inspection. H.4(b)

Enforcemerf[ Technical Specification 6.4, "Procedures," requires that written procedures be implemented for activities including "preventive and corrective maintenance operations which could have an effect on the safety of the reactor."

Contrary to the above, the requirements of EN-MA-118, "Foreign Material" were not fully implemented during the pump assembly portion of the work activity. This led to foreign material intrusion into the 'A' RHRSW train that rendered it inoperable from December 30, 2010 to January 7, 2011 . lmmediate corrective actions included conducting a "stand down," reinforcing the standards and requirements for FME controls and general procedural compliance, as well as reinforcing expectations for the attention to detail of work practices. Additionally, Entergy entered the issue into their corrective action program to evaluate for additional corrective measures. Because this finding is of very low safety significance and Entergy has entered it into their corrective action program (CR-WY-2011-0007), this violation is being treated as an NCV, consistent with the NRC Enforcement Policy. (NCV 0500027112011002-01: Failure to Follow Foreign Material Exclusion Procedure)

1R22 Surveillance Testino

a.

lnspection Scope (6 samples)

The inspectors observed six surveillance tests and/or reviewed test data of selected risk-significant SSCs to determine whether the testing adequately demonstrated equipment operational readiness and the ability to perform the intended safety functions. The inspectors reviewed selected prerequisites and precautions to determine if they were met; evaluated whether the tests were performed in accordance with the written procedure; determined whether the test data was complete and met procedural requirements; and assessed whether SSCs were properly returned to service following testing. The inspectors also verified that conditions adverse to quality were entered into the CAP for resolution. The documents reviewed are listed in the Attachment. The inspectors reviewed the following surveillance tests:

.

'A' Emergency Diesel Generator Monthly Surveillance;

.

Service Water Pump Testing;

.

'B' Loop RHFJRHRSW Pump and Valve Operability and Full Flow Test;

.

Main and Auxiliary Steam System Surveillance; r Quarterly Main Turbine Valve Performance Testing; and o Reactor Coolant System Leak Detection Surveillance (RCS LD).

b. Findinqs No findings were identified.

1EP6 Drill Evaluation

Emeroencv Preparedness Drill

a. Inspection Scope

(2 samples)

The inspectors observed an emergency preparedness (EP) drill on January 19,2411, and observed the player critiques. Entergy's EP staff preselected the drill notifications and protective action recommendations to be included in the EP drill performance indicator (Pl). The inspectors discussed the performance expectations and results with Entergy's EP staff to confirm correct implementation of the Pl program. The inspectors focused on the ability of licensed operators to perform event classifications and the ability of designated personnel to make proper notifications in accordance with Entergy's procedures and industry guidance. The inspectors evaluated the drillfor conformance with the requirements of 10 CFR Part 50, Appendix E, "Emergency Planning and Preparedness for Production and Utilization Facilities." The inspectors compared Entergy's self-identified issues with observations from the inspectors' review to ensure that performance issues were properly identified and documented. The documents reviewed are listed in the Attachment.

The inspectors observed licensed operator "as found" simulator training on February 7, 2011. The inspectors evaluated the operating crew activities related to accurate and timely classification and notification of an Alert. Additionally, the inspectors assessed the critique process used by the training evaluators for its ability to identify performance deficiencies. The documents reviewed are listed in the Attachment.

These activities constituted two drill evaluation inspection samples.

b. Findinqs No findings were identified.

4OA1 Performance Indicator (Pl) Verification

lnitiatino Events Cornerstone

a. Inspection Scope

The inspectors reviewed Entergy's submittals and Pl data for the cornerstones listed below for the period from January 201A to December 2010. The inspectors reviewed selected operator logs, plant process computer data, licensee event reports, and condition reports. The Pl definitions and guidance contained in Nuclear Energy Institute (NEl) 99-02, "Regulatory Assessment Performance lndicator Guideline," Revision 6, EN-Ll-1l4, "Performance Indicator Process," Revision 4, and AP 0094, 'NRC Performance lndicator Reporting," Revision 15, were used to verify the accuracy and completeness of the Pl data reported during this period. The Pls reviewed were:

.

Unplanned scrams per 7000 critical hours;

.

Unplanned power changes per 7000 critical hours; and r Unplanned scrams with complications.

b. Findinqs No findings were identified.

4OA2 ldentification and Resolution of Problems

.1 Reviews of ltems Entered into the Corrective Action Proqram

a. Inspection Scope

The inspectors performed a daily screening of each item entered into Entergy's CAP.

This review was accomplished by reviewing printouts of each CR, attending daily screening meetings, and/or accessing Entergy'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. Findinqs No findings or observations were identified.

.2 Operator Workarounds

a. Inspection Scope

(1 sample)

The inspectors reviewed the cumulative effect of operator workarounds, operator burdens, enhanced surveillances and control room deficiencies on the reliability, availability and potential mis-operation of mitigating systems with a particular focus on issues that had the potential to affect the ability of operators to respond to plant transients and events. The inspectors reviewed the auxiliary operator round sheets/turnover sheets for the reactor building, turbine building, and outside areas of the plant, and compared these with Entergy's listed operator burdens and workarounds.

The inspectors reviewed selected off-normal procedures and walked down related areas of the plant to determine whether the procedure steps could be implemented by operations personnel and required equipment was properly staged. ln addition, the inspectors reviewed Entergy tracking systems for operator burdens, control room deficiencies, and disabled control room alarms. The inspectors discussed selected issues with responsible operations personnel to ensure they were appropriately categorized and tracked for resolution.

b. Findinqs No findings or observations were identified.

4OA3 Event Follow-up

Inspection Scope (1 sample)

On February 16, 2011, while performing the quarterly surveillance test on the High Pressure Coolant system (HPCI) turbine, a steam leak developed at the flange on steam trap 23T-3 after full steam line pressure was applied to the trap during the test. HPCI room temperatures increased causing localfire alarms to activate. Based on the rapid rise in temperature in the HPCI room, operators manually isolated the HPCI system.

This action occurred before the room temperatures reached the automatic isolation set point for the HPCI system. The inspectors observed plant parameters from the control room and reviewed control room operator performance. The inspectors communicated the plant event to regional personnel and compared the event details with criteria contained in IMC 0309, "Reactive Inspection Decision Basis for Reactors," for consideration of additional reactive inspection activities. The inspectors reviewed Entergy's corrective actions to ensure they were implemented commensurate with their safety significance.

b. Findinqs and Observations

Introduction:

A self-revealing, Green NCV of Technical Specification 6.4, "Procedures,"

was identified in which maintenance and planning personnel did not involve engineering personnel as required by EN-MA-101, "Fundamentals of Maintenance," Revision 9, and EN-WM-105, "Planning," Revision 8, resulting in the incorrect material being used to replace the gasket on the flange of HPCI steam trap 23T-3. Entergy ultimately replaced the gasket with the correct material and entered this issue into their corrective action program.

Description:

On February 1, 2011, the HPCI system was removed from service to repair a small steam leak in non-safety related one-inch piping downstream of steam trap 23T-3. The flange on the trap had to be disassembled to access and replace the piping with the steam leak. The flange was originally sealed with a spiral wound flexitallic gasket.

This type of gasket was not readily available and the licensee determined that a Garlock 9920 gasket was an acceptable replacement. The decision was made by maintenance supervision based on a previous Technical Evaluation (04-00600 revision 0) provided in the work package by the planning department. This technical evaluation states that this material should not be used in systems greater than 250 psig. This limitation was overlooked and the Garlock 9920 gasket was put into place on 23T-3. Entergy procedure EN-MA-101 states that replacement components shall be "like for like," and EN-WM-105 states that the Procurement Engineering Group (PEG) be notified if items cannot be verified by procedure or EN-DC-313, "Procurement Engineering Process,"

Revision 5. Neither procedure was followed for the replacement gasket in this instance.

After replacing the steam trap flange gasket with Garlock 9920, the HPCI system was restored to standby status. Work Order (WO) 252692 required the piping and flange be tested for leakage at full system pressure (approximately 1000 psig). The post maintenance test (PMT) listed in the work order did not provide the operations department with detailed guidance in establishing initial conditions for the test.

Operators believed that the steam trap gasket was at the required PMT pressure when aligned to the standby configuration. However, with HPCI in a standby configuration, a series of two normally-opened isolation valves provided a drain pathway to the main condenser hotwell environment. Due to the low pressure condition at the steam trap flange gasket, the PMT had been inappropriately considered satisfactory, and Entergy declared the HPCI system to be operable on February 1.

On February 16, during HPCI quarterly surveillance testing, the steam trap and associated piping were exposed to full HPCI system steam pressure because the isolation valves to the main condenser automatically closed as part of the HPCI start-up sequence for the post-maintenance testing. The new gasket failed when exposed to pressure beyond its design rating, and allowed steam to escape between the flange and the steam trap body. The amount of steam that issued from 23T-3 was substantial enough to fill the room and raise the ambient temperature. Auxiliary operators in the HPCI room immediately reported the steam leak to the main control room, where licensed operators remotely isolated the HPCI steam line to stop the flow of steam.

This deficiency was entered into Entergy's corrective action program as CR-WY- 2011-00667. Entergy determined that the root cause of the event was determined to be the incorrect use of the Garlock 9920 materialfor the gasket. Additionally, Entergy determined that inadequate post maintenance testing was a contributing cause. On February 18,2011, Entergy replaced the 23T-3 flange gasket with the appropriate material, and completed a successful post maintenance test.

Analvsis: The inspectors determined that the installation of inappropriate material for the steam trap flange gasket was a performance deficiency which caused the HPCI system to be inoperable for greater than the time allowed by Technical Specifications. This performance deficiency was within Entergy's ability to foresee and correct and should have been prevented. Traditional enforcement does not apply as the issue did not have an actual safety consequence, had no willful aspects, nor did it impact the NRC's ability to perform its regulatory function.

The inspectors reviewed Inspection IMC 0612, Appendix E, "Minor Examples," and determined that this deficiency was not similar to any of the minor examples.

Additionally, using IMC 0612, "Power Reactor Inspection Reports," Appendix B, the inspectors determined that the finding was more than minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance in accordance with IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations,"

using significance determination process (SDP) Phases 1,2 and 3. Phase 1 screened the finding to Phase 2 because it represented an actual loss of the HPCI system safety function. A Region I Senior Reactor Analyst (SRA) conducted a Phase 3 analysis because the Phase 2 analysis, conducted by the inspectors using the W Pre-solved Risk-lnformed Inspection Notebook, indicated that the finding had the potential to be greater than very low safety significance (Greater than Green).

The SRA used the W Standardized Plant Analysis Risk (SPAR) model, Revision 8.16, to conduct the Phase 3 SDP evaluation, assuming that HPCI would not have been able to perform its safety function over the 19 day period from February 1 , 2011 to February 19,2011. This analysis indicated an increase in core damage frequency (ACDF) for internal initiating events in the range of 1 core damage accident in 4,000,000 years of reactor operation; in the low 1E-7 range per year. The dominate core damage sequences included the operator failure of HPCI and reactor core isolation cooling (RCIC), and the failure of operators to depressurize the reactor following a loss of main feedwater. ln accordance with IMC 0609, for a finding with an internal events ACDF greater than 1E-7, the SRA assessed the impact of the finding on: 1) External events such as fire, seismic and flooding, determining, based on review of the W Individual Plant Examination for External Events, that the total ACDF (internal plus external) would not be above the 1 E-6 threshold; and 2) the increase in large early release frequency (ALERF), determining that given the operators ability, following core damage, to depressurize and inject water to the reactor from low pressure sources and to flood the containment that the ALERF was in the low E-8 range. The Phase 3 SDP analysis determined that this issue was of very low safety significance (Green).

This issue has been entered into Vermont Yankee's corrective action program. The flange gasket for 23T-3 was immediately replaced with the correct material. Personnel involved in the event were coached on procedures for substituting material and components.

This finding had a cross-cutting aspect in the Human Performance cross-cutting area, Decision Making component, because Vermont Yankee personnel did not obtain interdisciplinary input on the decision to use a different, incorrect gasket material in a steam trap in the HPCI system. H.1(a)

Enforcement:

Technical Specification 6.4, "Procedures," requires that written procedures be implemented for preventive and corrective maintenance operations that could have an effect on the safety of the reactor. Contrary to this requirement, on February 1, 2011, the requirements of EN-MA-101, "Fundamentals of Maintenance," as well as, EN-WM-105, "Planning," were not properly implemented. Specifically, Entergy performed corrective maintenance to replace a HPCI system gasket that was not "like for like" (contrary to EN-MA-101), and the Procurement Engineering Group was not notified for the use of a new type of item (contrary to EN-WM-105). This action led to the HPCI system being inoperable from February 1,201 1 to February 19, 2011. lmmediate corrective actions included installation of the proper gasket, followed by successful completion of a proper post-installation pressure test of the gasket. Because of the very low safety significance (Green) and because it has been entered into the CAP (CR-VTY-2011-00667), the NRC is treating this finding as a NCV, consistent with the NRC Enforcement Policy. (NCV 0500027112011002-02: Steam Leak on High Pressure Coolant Injection (HPCI) During Surveillance Testing)

.2 (Closed) LER 05000271/2010-002-00&01: Inoperabilitv of Main Steam Safetv Relief

Valves Due to Deqraded Thread Seals (71153 - 1 sample)

During the 2010 refueling outage, the pneumatic actuators for the four main steam safety relief valves (SRVs) were tested and leakage was identified through the shaft-to-piston thread seal that was in excess of the design requirement on two of the four SRVs.

Material testing determined that the apparent cause of the degraded thread seal condition was thermal degradation. The thread seals were replaced and tested on all four SRVs prior to startup from the 2010 refueling outage.

Entergy determined that this potentially affected the ability of the SRVs to perform their manual and automatic depressurization function, as required by Technical Specifications, since the leakage impacted the ability of the SRVs to satisfy design actuation requirements. Entergy determined that there was firm evidence that this condition may have existed for a period of time greater than allowed by Technical Specifications, and therefore this event was reportable.

Due to the availability of a safety-class back-up nitrogen supply with separate pressure regulators, Entergy determined that adequate capacity for the Automatic Depressurization System (ADS)existed at all times. Due to the redundancy in ADS design, the availability of the HPCI system, and the availability of a safety-class backup nitrogen supply, the ability to depressurize the reactor was maintained, and there was no potential adverse impact to public health and safety.

The inspectors reviewed the subject LER, the as-found condition during the refueling outage, the subsequent material testing and analysis, and Entergy's evaluation of the condition. A violation of very low safety significance (Green) was identified by the licensee. The enforcement aspects of this finding are discussed in Section 4OA7. This LER is closed.

4OAO Meetinqs, includinq Exit Exit Meetino Summarv On April 11, 2011 , the resident inspectors presented the first quarter inspection results to Mr. Michael Colomb, Site Vice President, and other members of the Vermont Yankee staff. The inspectors confirmed that any proprietary information provided or examined during the inspection had been returned to the licensee.

4C.A7 Licensee-ldentified Violations The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements, which meet the criteria of the NRC Enforcement Policy for being dispositioned as non-cited violations.

.1 Technical Specification 3.5.F, "Automatic Depressurization System," allows up to one of

four SRVs in the automatic depressurization system to be inoperable for up to seven days at any time the reactor steam pressure is above 150 psig with irradiated fuel within the vessel, or an orderly shutdown of the reactor shall be initiated and the reactor pressure shall be reduced to less than 150 psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Contrary to the above, Entergy determined that two

(2) of the four

(4) SRVs were inoperable for a period of time greater than allowed by Technical Specifications. This determination was based on pneumatic actuator thread seal leakage that was identified during testing of the pneumatic SRV actuators in the 2010 refueling outage. Entergy determined the leakage to be in excess of design requirements. This condition has been entered in the licensee's corrective action program (CR-WY-2O10-2187) and corrective actions have been developed.

The inspectors determined that this finding was more than minor because it adversely affected the Mitigation Systems cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the function for core decay removalwas affected, since the safety function of the ADS valves is to depressurize the reactor to allow for low pressure coolant injection. The inspectors determined that this finding was not greater than Green, because subsequent laboratory analysis and engineering evaluation documented in Entergy Operability Recommendation WY 2011-0631 concluded that sufficient margin was available in the safety-class backup supply to the pneumatic actuation system. The inspectors reviewed Entergy's laboratory results and Operability Recommendation, and concluded that the ADS function would have been met under the worst case leakage for all design basis conditions.

,2 Technical Specification 3.6.D, "Safety and Relief Valves," requires the reactor to be shut down and pressure brought below 150 psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with two

(2) or more SRVs inoperable. Contrary to the above, Entergy determined that two

(2) of the four

(a) SRVs were inoperable for a period of time greater than allowed by Technical Specifications.

This determination was based on pneumatic actuator thread seal leakage that was identified during testing of the pneumatic SRV actuators in the 2010 refueling outage.

Entergy determined the leakage was in excess of design requirements, thereby rendering the SRV manual depressurization function inoperable. This condition has been entered in the licensee's corrective action program (CR-WY-2010-2187) and corrective actions have been developed.

The inspectors determined that this finding was more than minor because it adversely affected the Mitigation Systems cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the function for core decay heat removal was atfected, since the ability to manually discharge steam from core decay heat to the suppression pool was degraded by the thread seal leakage. The inspectors determined that this finding is not greater than Green, because subsequent laboratory analysis and engineering evaluation documented in Entergy Operability Recommendation VTY 2011-0631 concluded that sufficient margin was available in the safety-class backup supply to the pneumatic actuation system. The inspectors reviewed Entergy's laboratory results and Operability Recommendation, and concluded that the SRV manual depressurization function would have been met under the worst case leakage for all design basis conditions.

.3 10 CFR 50.65(a)(4) requires, in part, that before performing maintenance activities, the

licensee shall assess and manage the increase in risk that may result from proposed maintenance activities, Contrary to the above, on January 3,2011, Entergy did not adequately assess and manage the increase in risk due to proposed emergent maintenance activities. This resulted in a non-conservative risk assessment and failure to take all of the appropriate risk management actions for the actual plant conditions.

Entergy identified this after the emergent maintenance activities had been completed, and entered the issue into their corrective action program (CR-WY-2011-00028) to evaluate for appropriate corrective actions. The finding is more than minor because it is similar to IMC 0612, Appendix E, Example 7.e; in that, the overall elevated plant risk put the plant in a higher licensee-established risk category. The finding was evaluated using IMC 0609 Appendix K, "Maintenance Risk Assessment and Risk Management Significance Determination Process," and was determined to be of very low safety significance (Green) because the Incremental Core Damage Probability Deficit between the actual plant conditions and the incorrect risk assessment for the duration of the activity was less than 1.0 E-6 (approximately 3.3 E-9).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Vermont Yankee Personnel

M, Colomb, Site Vice President

C. Wamser, General Manager of Plant Operations

M. Romeo, Director of Nuclear Safety

R. Wanczyk, Licensing Manager

N. Rademacher, Director of Engineering

M. Gosekamp, Operations Manager

J. Rogers, Design Engineering Manager

J. Merkle, System Engineering Manager

D. Jones, Asst. Operations Manager

P. Ryan, Security Manager

B. Pittman, Assistant Operations Manager

M. Tessier, Maintenance Manager

J. Hardy, Chemistry Manager

P. Corbett, Quality Assurance Manager

S. Naeck, Outage Manager

J. Bengtson, CA&A Manager

M. Castronova, Manager of Projects

J. Ward, l&C Superintendent

R. Heathwaite, Chemistry Supervisor

C. Daniels, FIN Team Superintendent

R. Current, Sr. Electrical l&C System Engineer

L. Doucette, System Engineer

J. Devincentis, Licensing Engineer

P. Couture, Licensing Specialist

J. Meyer, Licensing Specialist

M. Morgan, Technical Training Superintendent

M. Anderson, Fire Protection Engineer

M. Pletcher, Shift Technical Advisor

K. Oliver, Shift Manager

V. Ferrizzi, Shift Manager

J. Miller, Auxiliary Operator

J. Kritzer, Shift Technical Advisor

D. Hensel, Work Week Manager

F. Aldrich, Control Room Supervisor

N. Jennison, Shift Manager

G. Bacala, Control Room Supervisor

J. Clough, System Engineer

D. Macie, Facilities

S. Nelson, Fire Brigade lnstructor

J. Stasolla, Mechanical Systems Engineer

B. Pelzer, Code Programs Engineer

A. Robertshaw, Mechanical Design Engineer

P. Jerz, Work Week Manager

J. Devine, Auxiliary Operator

S. Jonasch, Mechanical Systems Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000271/201 1002-01 NCV Failure to Follow Foreign Material Exclusion Procedure (Section 1R19)

05000271/2011002-02 NCV Steam Leak on High Pressure Coolant lnjection (HPCI)

During Surveillance Testing (Section 4OA3)

Closed

0500027 1 120 1 0-002-00&01 LER Inoperability of Main Steam Safety Relief Valves Due to Degraded Thread Seals (Section 4OA3)