IR 05000382/2011005

IR 05000382-11-005, on October 1, 2011 - December 31, 2011, Waterford Steam Electric Station, Unit 3 - NRC Integrated Inspection Report

ML120400136
Person / Time
Site:	Waterford
Issue date:	02/08/2012
From:	Allen D NRC/RGN-IV/DRP/RPB-E
To:	Jacobs D Entergy Operations
References
IR-11-005
Download: ML120400136 (72)

Text

February 8, 2012

Donna Jacobs, Vice President, Operations Entergy Operations, Inc.

Waterford Steam Electric Station, Unit 3 17265 River Road

Killona, LA 70057-0751

Subject:

WATERFORD STEAM ELECTRIC STATION, UNIT 3 - NRC INTEGRATED

INSPECTION REPORT 05000382/2011005

Dear Ms. Jacobs:

On December 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Waterford Steam Electric Station, Unit 3. The enclosed inspection report documents the inspection results which were discussed on January 19, 2012, with you and other members of your staff.

The inspections examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

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

Four NRC identified findings of very low safety significance (Green) were identified during this inspection.

These findings were determined to involve violations of NRC requirements. Additionally, the NRC has determined that a traditional enforcement Severity Level IV violation occurred.

Further, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC Enforcement Policy.

If you contest these non-cited violations, 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 IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Waterford Steam Electric Station, Unit 3 facility.

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION IV

1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511 If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at the Waterford Steam Electric Station, Unit 3 facility.

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 NRC's Agencywide Document Access and Management 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/

Donald B. Allen Chief, Project Branch E Division of Reactor Projects

Docket No.:

05000382 License No.:

NPF-38

Enclosure:

Inspection Report 05000382/2011005 Attachments 1.

Supplemental Information 2.

Information Request for inspection activities documented in

71124.06, 71124.07, and 71124.08

cc: w/encl: Electronic Distribution

SUMMARY OF FINDINGS

IR 05000382/2011005; 10/01/2011-12/31/2011; Waterford Steam Electric Station, Unit 3,

Integrated Resident Report; Heat Sink Perf., Maint. Effect., Rad. Solid Waste Process & Rad.

Material Handl. Stor. & Transp., Perf. Ind. Ver., Prob. Ident. & Resolution

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by regional based inspectors. Four Green non-cited violations of significance were identified. In addition, one Severity Level IV non-cited violation of significance was identified. The significance of most findings is indicated by their color (Green, White,

Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process.

The crosscutting aspect is determined using Inspection Manual Chapter 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.

The inspectors identified a non-cited violation of 10CFR50, Appendix B,

Criterion XVI because the licensee failed to identify and correct a condition adverse to quality associated with the main feedwater isolation valve. Specifically, the licensee did not identify that varnish deposits were causing the main feedwater isolation valve to fail its inservice testing. As a result, corrective actions that were implemented did not address the adverse condition, leading to a subsequent test failure. The licensee entered this issue into their corrective action program as CR-WF3-2011-2005 and CR-WF3-2011-8140. The corrective actions included the replacement of the actuator, a shortening of the replacement frequency of the four-way hydraulic valves to a 36 month interval, and an evaluation of the current methods of gathering and implementing operating experience.

The performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the main feedwater isolation valve is credited for closure during a main feedwater line break. The inspectors performed the initial significance determination using the NRC Inspection Manual 0609, Attachment 0609.04,

Phase 1 - Initial Screening and Characterization of Findings. The finding screened to a Phase 2 significance determination because it involved a loss of one train of safety related equipment for longer than the technical specification allowed outage time. A Region IV senior reactor analyst performed a Phase 2 significance determination and used the pre-solved worksheet from the Risk Informed Inspection Notebook for the Waterford-3 Nuclear Power Plant, Revision 2.01a.

However, the main feedwater isolation valves were not included in the pre-solved worksheet and the valves did not appear as components in the Phase 2 significance determination worksheets. The senior reactor analyst performed a Phase 3 significance determination for this issue. The analyst noted that the main feed isolation valves were not a significant contributor to core damage frequency and were not included in the NRCs SPAR model. These valves close to mitigate core overcooling events or to isolate feedwater flow to a ruptured feedwater line inside containment. Overcooling events do not lead to core damage. A ruptured feedwater line could challenge containment integrity, but without core damage there would be no potential for a large early release. If a valve failed to close on demand, the licensee had other means to isolate feedwater flow to a steam generator or into containment. Operators could secure feedwater pumps, close a block valve, or close the main feedwater flow control valves. Accordingly, the contribution to core damage was much less than E-6. Therefore, the inspectors determined that this finding had very low safety significance (Green). This finding has a cross-cutting aspect in the operating experience component of the problem identification and resolution area in that the licensee did not collect and evaluate relevant external operating experience to identify that other sites experienced similar failures of feedwater isolation valves due to varnish deposits on the interior surface [P.2.(a)] (Section 1R12).

Green.

The inspectors identified a non-cited violation of 10CFR50, Appendix B,

Criterion III because the licensee did not translate applicable regulatory requirements and the design basis into specifications and instructions.

Specifically, the licensee did not translate the design basis tornado event into a design calculation. This outage-specific calculation was referenced by operations as the basis to ensure that the number of dry cooling tower fans needed for decay heat removal remained available. As a result, additional analysis needed to be performed to verify that the ultimate heat sink would have been able to perform its design function had a design basis tornado occurred during refueling outage RF-17. The licensee entered this issue into their corrective action program as CR-WF3-2011-6480. The immediate corrective actions taken to restore compliance included analysis of the condition and actions to ensure that future outage specific calculations include the tornado design basis event.

The performance deficiency is more than minor because it challenges the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Since the calculation was used when the plant was shutdown, the inspectors used Manual Chapter 0609,

Appendix G, "Shutdown Operations Significance Determination Process, and Appendix G, Attachment 1, "Shutdown Operations Significance Determination Process Phase 1 Operational Checklists." The issue was determined to have a very low safety significance (Green) because it did not require a quantitative assessment. Through calculation review, the inspectors concluded that this failure resulted in the potential to enter an unanalyzed condition. This finding had a crosscutting aspect in the resources component of the human performance area in that the licensee failed to incorporate accurate design information into instructions

[H.2.(c)] (Section 4OA1.2).

Green.

The inspectors identified a non-cited violation of Technical Specification 6.8.1.a because the licensee did not follow work order instructions to install a pressure gage in an air line used to measure and maintain pressure for the hydraulic accumulators that close the main feedwater isolation valve. Specifically, the licensee did not follow the instructions to assemble and tighten a Swagelok fitting according to the work order. As a result, the fitting failed, preventing the valve from being able to perform its safety-related function. The licensee entered this issue into their corrective action program as CR-WF3-2010-1166 and CR-WF3-2011-7469. The immediate corrective actions included repairing the Swagelok fitting and completing an apparent cause evaluation to determine the nature of the fitting failure and failure to follow procedure.

The performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspector performed the initial significance determination using NRC Inspection Manual 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. The finding screened to a Phase 2 significance determination because it involved a potential loss of one train of safety related equipment for longer than the technical specification allowed outage time. A Region IV senior reactor analyst performed a Phase 2 significance determination and used the pre-solved worksheet from the Risk Informed Inspection Notebook for the Waterford-3 Nuclear Power Plant, Revision 2.01a. However, the main feedwater isolation valves were not included in the pre-solved worksheet and the valves did not appear as components in the Phase 2 significance determination worksheets. The senior reactor analyst performed a Phase 3 significance determination for this issue. The analyst noted that the main feed isolation valves were not a significant contributor to core damage frequency and were not included in the NRCs SPAR model. These valves close to mitigate core overcooling events or to isolate feedwater flow to a ruptured feedwater line inside containment.

Overcooling events do not lead to core damage. A ruptured feedwater line could challenge containment integrity, but without core damage there would be no potential for a large early release. If a valve failed to close on demand, the licensee had other means to isolate feedwater flow to a steam generator or into containment. Operators could secure feedwater pumps, close a block valve, or close the main feedwater flow control valves. Accordingly, the contribution to core damage was much less than E-6. As a result, this finding had a very low safety significance (Green). This finding does not have a crosscutting aspect since it is not indicative of current plant performance (Section 4OA2.4).

Cornerstone: Barrier Integrity

Green.

The inspectors identified a non-cited violation of Technical Specification Limiting Condition for Operation 3.6.2.2, Containment Cooling System, which requires in Modes 1, 2, 3, and 4 that Two independent trains of containment cooling shall be OPERABLE with one fan cooler to each train. The Technical

Specification Action statement requires that With one train of containment cooling inoperable, restore the inoperable train to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; restore the inoperable containment cooling train to OPERABLE status within the next 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in COLD SHUTDOWN within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Specifically, from July 11, 2009, to July 19, 2009, the licensee failed to declare train B of the containment cooling system inoperable, and restore it to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or place the unit in hot standby in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. This finding has been entered into the licensees corrective action program as Condition Reports CR-WF3-2011-08150.

The inspectors determined that the failure to meet Technical Specification Limiting Condition for Operation 3.6.2.2 was a performance deficiency. The finding was more than minor because it adversely affected the structures, systems, and components and barrier performance attribute of the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the component cooling water flow for containment cooling system train B decreased below the minimum flow limits of Technical Specification Surveillance Requirement 4.6.2.2. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the issue was determined to have very low safety significance (Green)because it did not represent an actual open pathway in the physical integrity of reactor containment and heat removal components, and did not involve an actual reduction in the function of hydrogen igniters in the reactor containment. This finding was determined to have a crosscutting aspect in the area of human performance associated with the decision making component because the licensee did not use conservative assumptions in decision making and adopt a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action

[H.1.(b)] (Section 1R07).

Cornerstone: Public Radiation Safety

• Severity Level IV. The inspectors identified a non-cited violation of 10 CFR 50.71 Maintenance of Records, because the licensee failed to update their updated final safety analysis report with submittals that include a change made to the facility.

Specifically, the licensee built the low level radwaste storage facility in 1995 on the owner controlled area for interim radwaste storage of dry and solidified radioactive waste and failed to update the updated final safety analysis report to include these changes. This issue was entered in the licensees corrective action program as condition report WF3-2011-07711.

This issue was dispositioned using traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. The finding is more than minor because it has a material impact on licensed activities in that stored radwaste materials with a significant radioactive source term has been relocated from the plant radiologically controlled area to the owner controlled area.

In addition, the radwaste management program has been affected because the licensee was not originally licensed to act as a low level waste facility. However, the termination of the Barnwell Low Level Radioactive Waste Management facility has forced the licensee to build such a storage area and make changes to the facility, significantly increasing the onsite storage capacity. The inspectors determined that this finding did not reflect present performance because it is an issue with changes made to the facility more than 15 years previously. Therefore, there was no cross-cutting aspect associated with this finding. This finding is characterized as a Severity Level IV non-cited violation in accordance with NRC Enforcement Policy, Section 6.1, and was treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy (Section 2RS08).

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

The Waterford Steam Electric Station, Unit 3, began the inspection period at approximately 100 percent power and remained at approximately 100 percent power for the rest of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignments

Partial Walkdown a.

The inspectors performed partial system walkdowns of the following risk-significant systems:

Inspection Scope

• On October 5, 2011, train B of the electrical distribution switchgear and emergency diesel generators A and B during a scheduled maintenance outage of startup transformer A

• On October 11, 2011, train B of the component cooling water system during emergent maintenance on train A

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, updated final safety analysts report, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two

(2) partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b.

No findings were identified.

Findings

1R05 Fire Protection

Quarterly Fire Inspection Tours a.

The inspectors conducted fire protection walkdowns that were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

Inspection Scope

• On September 28, 2011, reactor auxiliary building -35 foot elevation fire area RAB 40, diesel storage tank A

• On September 28, 2011, reactor auxiliary building -35 foot elevation fire area RAB 41, diesel storage tank B

• On November 21, 2011, reactor auxiliary building +21 foot elevation fire zone RAB 8A, vital switchgear room A

• On November 23, 2011, reactor auxiliary building +35 foot elevation fire area RAB 5, electrical penetration room B

The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four

(4) quarterly fire-protection inspection samples as defined in Inspection Procedure 71111.05-05.

b.

No findings were identified.

Findings

1R06 Flood Protection Measures

a.

The inspectors reviewed the updated final safety analysts report, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding; reviewed the corrective action program to determine if licensee personnel identified and corrected flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. The inspectors also inspected the areas listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers.

Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

• On December 22, 2011, reactor auxiliary building and dry cooling tower areas

These activities constitute completion of one

(1) bunker/manhole sample as defined in Inspection Procedure 71111.06-05.

b.

No findings were identified.

Findings

1R07 Heat Sink Performance

a.

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the following heat exchangers:

Inspection Scope

• containment cooling system fan cooler train B, 3B-SB and 3D-SB

• diesel jacket water cooler train 3A-S

• essential water chiller, train A

The inspectors verified that performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the periodic maintenance method outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines, the licensee properly utilized biofouling controls;

the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchangers were correctly categorized under 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three

(3) triennial heat sink inspection samples as defined in Inspection Procedure 71111.07-05.

b. Findings

Inoperable Train of Containment Cooling System

Introduction.

The inspectors identified a Green non-cited violation of Waterford 3 Technical Specification 3.6.2.2, Containment Cooling System. Specifically, the licensee failed to meet Technical Specification Limiting Condition for Operation 3.6.2.2 to have two independent operable trains of containment cooling with one fan cooler to each train while in Mode 1.

Description.

The inspectors reviewed the calendar year 2009 trends of component cooling water flow through train B of the containment cooling system. Train B of the containment cooling system consists of containment fan coolers B and D. The inspectors observed that, from July 8, 2009, to July 19, 2009, the component cooling water flow rate decreased below the Surveillance Requirement 4.6.2.2 acceptance criteria flow rate of 625 gallons per minute (gpm) for each containment fan cooler.

The inspectors reviewed the control room operator logs during the 11 day time period to determine if the control room operators declared train B of the containment cooling system inoperable. The control room operator logs contained no declaration for the containment cooling system. Additionally, no entry into the Technical Specification Action 3.6.2.2 was made.

Technical Specification Surveillance Requirement 4.6.2.2 states:

Each train of containment cooling shall be demonstrated OPERABLE:

a. At least once per 31 days by:

1. Starting each operational fan not already running from the control room and

verifying that each operational fan operates for at least 15 minutes.

2. Verifying a cooling water flow rate of greater than or equal to 625 gpm to

each cooler.

Additionally, the basis for Surveillance Requirement 4.6.2.2 states, Operating each containment cooling train fan unit for 15 minutes and verifying a cooling water flow rate of 625 gpm ensures that all trains are OPERABLE and that all associated controls are functioning properly.

The inspectors determined that the decreased component cooling water flow for both containment fan coolers B and D was an indication to the operators that the train B containment cooling system temperature control valve, CC-835B, was not functioning properly. Additionally, because flow was below the surveillance requirement acceptance criteria, the licensee could not ensure that the surveillance requirement could be met.

The surveillance requirement applicability, Surveillance Requirement 4.0.1 states, in part, Surveillance Requirements shall be met during the MODES or other specified in the Applicability for individual [Limiting Condition for Operation], unless otherwise stated in the Surveillance. Failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the [Limiting Condition for Operation]. Based on this information, train B of the containment cooling system should have been declared inoperable on July 8, 2009, and the licensee should have entered Technical Specification Action 3.6.2.2 to restore train B to operable status. Train B of the containment cooling system was restored to an operable but degraded configuration on July 19, 2009, when operators removed containment fan cooler B from service and established the required flow through containment fan cooler D. The licensee later repaired the CC-835B valve control system air regulators and solenoids to correct the adverse conditions.

The licensee previously identified low component cooling water flow conditions to containment fan cooler B on at least four occasions in 2008 and 2009. The most recent low flow condition was identified on July 6, 2009. On each occasion, the operability determinations stated that CR-WF3-2003-0856 provides the Licensing position that not achieving 625 gpm does not mean the [containment fan coolers] are inoperable or that entry into TS 3.6.2.2 is required. The licensing position was based on a review of regulatory documentation, Standard Technical Specifications for Combustion Engineering plants, and technical specification from other plants that did not incorporate a minimum flow value. In addition, the minimum flow value was not used in the Waterford 3 Updated Safety Analysis Report. Therefore, the licensee declared the containment cooling system operable.

The inspectors determined that the basis for operability was invalid because the justification in CR-WF3-2003-0856 was contrary to the applicability statement of Surveillance Requirement 4.0.1. Additionally, using the justification of CR-WF3-2003-0856 caused the licensee to miss an opportunity to declare train B of the containment cooling system inoperable and enter the Technical Specification Action 3.6.2.2 on July 8, 2009, when flow decreased below the minimum value of Surveillance Requirement 4.6.2.2.

Analysis.

The inspectors determined that the failure to meet Technical Specification Limiting Condition for Operation 3.6.2.2 was a performance deficiency. The finding is more than minor because it adversely affected the structures, systems, and components and barrier performance attribute of the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the component

cooling water flow for train B of the containment cooling system decreased below the minimum flow limits of Technical Specification Surveillance Requirement 4.6.2.2. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the issue was determined to have very low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of reactor containment and heat removal components, and did not involve an actual reduction in the function of hydrogen igniters in the reactor containment. The finding had a crosscutting aspect in the area of human performance, decision making component, because the licensee decisions failed to demonstrate that nuclear safety is an overriding priority. This finding was determined to have a crosscutting aspect in the area of human performance associated with the decision making component because the licensee did not use conservative assumptions in decision making and adopt a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action. Specifically, the licensee failed to use conservative assumptions in decision making when determining the operability of containment cooling system. H.1(b)

Enforcement.

Technical Specification Limiting Condition for Operation 3.6.2.2, Containment Cooling System, requires in Modes 1, 2, 3, and 4 that Two independent trains of containment cooling shall be OPERABLE with one fan cooler to each train.

The Technical Specification Action statement requires that With one train of containment cooling inoperable, restore the inoperable train to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; restore the inoperable containment cooling train to OPERABLE status within the next 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in COLD SHUTDOWN within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Contrary to the above, from July 11, 2009, to July 19, 2009 the licensee failed to have two operable independent trains of containment cooling with one fan cooler to each train. Specifically, while in Mode 1, the licensee failed to declare train B of the containment cooling system inoperable, then failed to restore it to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or place the unit in hot standby in the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. This finding has been entered into the licensees corrective action program as Condition Report CR-WF3-2011-08150. Because this finding is of very low safety significance and was entered into the licensees corrective action program, this violation is being treated as a non-cited violation, consistent with the NRC Enforcement Policy: NCV 05000382/2011005-01: Inoperable Train of Containment Cooling System.

1R11 Licensed Operator Requalification Program

a.

On October 24, 2011, the inspectors observed a crew of licensed operators in the plants simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

Inspection Scope

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications

The inspectors compared the crews performance in these areas to preestablished operator action expectations and successful critical task completion requirements.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one

(1) quarterly licensed-operator requalification program sample as defined in Inspection Procedure 71111.11.

b.

No findings were identified.

Findings

1R12 Maintenance Effectiveness

a.

The inspectors evaluated degraded performance issues involving the following risk significant systems:

Inspection Scope

• On October 13, 2011, auxiliary component cooling water outlet temperature control valve (ACC-126A) on the A header

• On October 25, 2011, repetitive failures of main feedwater isolation valve in-service testing

• On December 21, 2011, emergency feedwater pump steam supply check valve (MS-402B)

The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

• Scoping of systems in accordance with 10 CFR 50.65(b)

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)

• Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1)

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three

(3) quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b.

Introduction.

The inspectors identified a Green non-cited violation of 10CFR50, Appendix B, Criterion XVI because the licensee failed to identify and correct a condition adverse to quality. Specifically, the licensee did not identify that varnish deposits were causing the main feedwater isolation valve to fail its inservice testing. As a result, corrective actions that were implemented did not address the adverse condition, leading to a subsequent test failure.

Findings

Description.

During a 2009 inservice test (IST), both main feedwater isolation valves (MFIV) failed to close in the required time period. The licensee performed an apparent cause evaluation and determined that the failure was caused by gelling of the Fyrquel hydraulic fluid due to an introduction of moisture in the lines. Based on the causal investigation, the licensee implemented corrective actions to monitor hydraulic fluid quality and increase the replacement frequency. The inspectors noted that the licensees review of industry operating experience provided no new information.

In 2011, during the next IST, both MFIVs again failed to meet the test acceptance criteria. The root cause was determined to be varnish deposits on the interior surface of the four-way hydraulic actuator valves. The varnish deposits interfered with the piston operation, causing it to stick. The licensee concluded that the interior of the four-way hydraulic valves probably had a varnish build-up for some time, but it did not interfere with valve operation until the applied pneumatic pressure was reduced from 115 psi to 88 psi to comply with system design specifications. This design change was performed in May 2008 per engineering change EC-4598.

Industry operating experience showed that a similar condition occurred at another site in 2000. Varnish deposits on the interior surface of a MFIV four-way hydraulic valve prevented the valve from stroking closed. The inspectors determined that this information was readily available during the apparent cause evaluation operating experience review in 2009, however it was not identified as pertinent at the time.

A review of the safety analysis showed that a failure of the MFIV to close on demand would have very low safety significance since other valves, such as the feedwater regulating valve, would have closed to isolate an affected steam generator. The licensee entered this condition into the corrective action program as CR-WF3-2011-2005 and CR-WF3-2011-8140. The corrective actions included the replacement of the actuator, a shortening of the replacement frequency of the four-way hydraulic valves to a 36 month interval, and an evaluation of the current methods of gathering and implementing operating experience.

Analysis.

The failure to identify and correct a condition adverse to quality is a performance deficiency. The inspectors determined that this issue was reasonably within the licensees ability to foresee and correct and should have been prevented.

This performance deficiency is more than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the main feedwater isolation valve is credited for closure during a main feedwater line break. The inspectors performed the initial significance determination for the main feedwater isolation valve failure using the NRC Inspection Manual 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. The finding screened to a Phase 2 significance determination because it involved a loss of one train of safety related equipment for longer than the technical specification allowed outage time. A Region IV senior reactor analyst performed a Phase 2 significance determination and used the pre-solved worksheet from the Risk Informed Inspection Notebook for the Waterford-3 Nuclear Power Plant, Revision 2.01a. However, the main feedwater isolation valves were not included in the pre-solved worksheet and the valves did not appear as components in the Phase 2 significance determination worksheets. The senior reactor analyst performed a Phase 3 significance determination for this issue.

The analyst noted that the main feed isolation valves were not a significant contributor to core damage frequency and were not included in the NRCs SPAR model. These valves close to mitigate core overcooling events or to isolate feedwater flow to a ruptured feedwater line inside containment. Overcooling events do not lead to core damage. A ruptured feedwater line could challenge containment integrity, but without core damage

there would be no potential for a large early release. If a valve failed to close on demand, the licensee had other means to isolate feedwater flow to a steam generator or into containment. Operators could secure feedwater pumps, close a block valve, or close the main feedwater flow control valves. Accordingly, the contribution to core damage was much less than E-6 and this finding had very low safety significance (Green). This finding has a cross-cutting aspect in the operating experience component of the problem identification and resolution area in that the licensee did not collect and evaluate relevant external operating experience to identify that other sites experienced similar failures of feedwater isolation valves due to varnish deposits on the interior surface [P.2.(a)].

Enforcement.

Title 10 of CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that conditions adverse to quality are promptly identified and corrected.

Contrary to the above, in 2009 the licensee did not promptly identify the adverse condition (varnish deposits) during their causal determination. This condition existed from the first failure, until causal determination and repair in 2011. This violation was entered into the licensees corrective action program as CR-WF3-2011-2005 and CR-WF3-2011-8140. Corrective actions include a shortening of the replacement frequency of the four-way hydraulic valves to a 36 month interval and an evaluation of the current methods of gathering and implementing operating experience. This violation of Appendix B, Criterion XVI, is being treated as an NRC identified non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy: NCV 05000382/2011005-02, Failure to Identify and Correct a Condition Adverse to Quality Associated with the Main Feedwater Isolation Valves.

1R13 Maintenance Risk Assessments and Emergent Work Control

a.

The inspectors reviewed licensee personnel's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

Inspection Scope

• On October 20, 2011, emergent maintenance activities on the essential chilled water loop B with scheduled maintenance on the emergency feedwater pump AB

The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one

(1) maintenance risk assessments and emergent work control inspection sample as defined in Inspection Procedure 71111.13-05.

b.

No findings were identified.

Findings

1R15 Operability Evaluations

a.

The inspectors reviewed the following issues:

Inspection Scope

• On October 2, 2011, operability evaluation of the auxiliary component cooling water train A

• On October 18, 2011, operability evaluation of the containment cooler temperature control valve (CC-835B) on train B

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and updated final safety analysis report to the licensee personnels evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two

(2) operability evaluations inspection samples as defined in Inspection Procedure 71111.15-04

b.

No findings were identified.

Findings

1R19 Postmaintenance Testing

a.

The inspectors reviewed the following postmaintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

Inspection Scope

• On October 14, 2011, emergent corrective maintenance on the auxiliary component cooling water outlet temperature control valve (ACC-126A) on header A

• On October 19, 2011, emergent corrective maintenance on the train B containment cooler temperature control valve (CC-835B)

• On November 8, 2011, corrective maintenance on the train B feedwater isolation valve FW-184B pneumatic pressure switch line following a nitrogen leak from a loose Swagelok fitting

• On November 10, 2011,corrective maintenance to replace leaking relief valve RFR-107C on essential chiller AB

The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following (as applicable):

• The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed

• Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate

The inspectors evaluated the activities against the technical specifications, the updated final safety analysts report, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with postmaintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four

(4) postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b.

No findings were identified.

Findings

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the updated final safety analysts report, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints

The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• On October 14, 2011, emergent surveillance to verify operability of the train A auxiliary component cooling water outlet temperature control valve (In-service Test)

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one

(1) surveillance testing inspection sample as defined in Inspection Procedure 71111.22-05.

b.

No findings were identified.

Findings

1EP1 Exercise Evaluation

a. Inspection Scope

The inspectors reviewed the objectives and scenario for the 2011 biennial emergency plan exercise to determine if the exercise would acceptably test major elements of the emergency plan. The scenario simulated a response to a terrorist threat, malfunctions in a safety uninterruptible power supply, fire alarm panel, and a pressurizer pressure instrument; a steam generator tube leak, a high pressure safety injection suction flange leak, malfunctions with an essential chiller, containment spray pump, a charging pump, instrument air leakage, and an emergency feedwater pump; a reactor coolant pump shaft seizure combined with a failure of the reactor protection system to initiate an automatic reactor trip, which led to core damage, fission product barrier failures, and a radiological release to the environment via a failed open steam generator atmospheric dump valve to demonstrate the licensee's capabilities to implement the emergency plan.

The inspectors evaluated exercise performance by focusing on the risk-significant activities of event classification, offsite notification, recognition of offsite dose consequences, and development of protective action recommendations, in the control room simulator and the following dedicated emergency response facilities:

• Technical Support Center

• Operations Support Center

• Emergency Operations Facility

The inspectors also assessed recognition of and response to abnormal and emergency plant conditions, the transfer of decision-making authority and emergency function responsibilities between facilities, onsite and offsite communications, protection of emergency workers, emergency repair evaluation and capability, and the overall

implementation of the emergency plan to protect public health and safety and the environment. The inspectors reviewed the current revision of the facility Emergency Plan, and emergency plan implementing procedures associated with operation of the above facilities and performance of the associated emergency functions. These procedures are listed in the attachment to this report.

The inspectors compared the observed exercise performance with the requirements in the facility Emergency Plan, 10 CFR 50.47(b), 10 CFR 50 Appendix E, and with the guidance in the emergency plan implementing procedures and other federal guidance.

The inspectors attended the post-exercise critiques in each of the above facilities to evaluate the initial licensee self-assessment of exercise performance. The inspectors also attended a subsequent formal presentation of critique items to plant management.

These activities constitute completion of one

(1) sample as defined in Inspection Procedure 71114.01-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspectors performed on-site reviews of the Waterford 3 Emergency Plan, Revision 41, and emergency plan implementing procedure EP-001-001, Recognition and Classification of Emergency Conditions, Revision 29. These revisions changed the basis of the licensees emergency action level scheme from Nuclear Energy Institute Report 99-01, Revision 4, to Nuclear Energy Institute Report 99-01, Revision 5. The licensees Nuclear Energy Institute Report 99-01, Revision 5, scheme was approved by the NRC by letter dated July 18, 2011 (ADAMS Accession Number ML111380558).

These revisions were compared to their previous revisions, to the criteria of NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, to Nuclear Energy Institute Report 99-01, Emergency Action Level Methodology, Revisions 4 and 5, and to the standards in 10 CFR 50.47(b) to determine if the revisions adequately implemented the requirements of 10 CFR 50.54(q). This review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, these revisions are subject to future inspection. The specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two

(2) samples as defined in Inspection Procedure 71114.04-05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Training Observations a.

The inspectors observed a simulator training evolution for licensed operators on October 25, 2011, which required emergency plan implementation by a licensee operations crew. This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the corrective action program. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the attachment.

Inspection Scope

These activities constitute completion of one

(1) sample as defined in Inspection Procedure 71114.06-05.

b.

No findings were identified.

Findings

2RS0 6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

This area was inspected to:

(1) ensure the gaseous and liquid effluent processing systems are maintained so radiological discharges are properly mitigated, monitored, and evaluated with respect to public exposure;

(2) ensure abnormal radioactive gaseous or liquid discharges and conditions, when effluent radiation monitors are out-of-service, are controlled in accordance with the applicable regulatory requirements and licensee procedures;

(3) verify the licensees quality control program ensures the radioactive effluent sampling and analysis requirements are satisfied so discharges of radioactive materials are adequately quantified and evaluated; and

(4) verify the adequacy of public dose projections resulting from radioactive effluent discharges. The inspectors used the requirements in 10 CFR Part 20; 10 CFR Part 50, Appendices A and I; 40 CFR Part 190; the Offsite Dose Calculation Manual, and licensee procedures required by the technical

specifications as criteria for determining compliance. The inspectors interviewed licensee personnel and reviewed and/or observed the following items:

• Radiological effluent release reports since the previous inspection and reports related to the effluent program issued since the previous inspection, if any

• Effluent program implementing procedures, including sampling, monitor setpoint determinations and dose calculations

• Equipment configuration and flow paths of selected gaseous and liquid discharge system components, filtered ventilation system material condition, and significant changes to their effluent release points, if any, and associated 10 CFR 50.59 reviews

• Selected portions of the routine processing and discharge of radioactive gaseous and liquid effluents (including sample collection and analysis)

• Controls used to ensure representative sampling and appropriate compensatory sampling

• Results of the inter-laboratory comparison program

• Effluent stack flow rates

• Surveillance test results of technical specification-required ventilation effluent discharge systems since the previous inspection

• Significant changes in reported dose values, if any

• A selection of radioactive liquid and gaseous waste discharge permits

• Part 61 analyses and methods used to determine which isotopes are included in the source term

• Offsite dose calculation manual changes, if any

• Meteorological dispersion and deposition factors

• Latest land use census

• Records of abnormal gaseous or liquid tank discharges, if any

• Groundwater monitoring results

• Changes to the licensees written program for indentifying and controlling contaminated spills/leaks to groundwater, if any

• Identified leakage or spill events and entries made into 10 CFR 50.75 (g)records, if any, and associated evaluations of the extent of the contamination and the radiological source term

• Offsite notifications and reports of events associated with spills, leaks, or groundwater monitoring results, if any

• Audits, self-assessments, reports, and corrective action documents related to radioactive gaseous and liquid effluent treatment since the last inspection

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one

(1) required sample, as defined in Inspection Procedure 71124.06-05.

b. Findings

No findings were identified.

2RS0 7 Radiological Environmental Monitoring Program

a. Inspection Scope

This area was inspected to:

(1) ensure that the radiological environmental monitoring program verifies the impact of radioactive effluent releases to the environment and sufficiently validates the integrity of the radioactive gaseous and liquid effluent release program;

(2) verify that the radiological environmental monitoring program is implemented consistent with the licensees technical specifications and/or offsite dose calculation manual, and to validate that the radioactive effluent release program meets the design objective contained in Appendix I to 10 CFR Part 50; and

(3) ensure that the radiological environmental monitoring program monitors non-effluent exposure pathways, is based on sound principles and assumptions, and validates that doses to members of the public are within the dose limits of 10 CFR Part 20 and 40 CFR Part 190, as applicable. The inspectors reviewed and/or observed the following items:

• Annual environmental monitoring reports and offsite dose calculation manual

• Selected air sampling and thermoluminescence dosimeter monitoring stations

• Collection and preparation of environmental samples

• Operability, calibration, and maintenance of meteorological instruments

• Selected events documented in the annual environmental monitoring report which involved a missed sample, inoperable sampler, lost thermoluminescence dosimeter, or anomalous measurement

• Selected structures, systems, or components that may contain licensed material and has a credible mechanism for licensed material to reach ground water

• Records required by 10 CFR 50.75(g)

• Significant changes made by the licensee to the offsite dose calculation manual as the result of changes to the land census or sampler station modifications since the last inspection

• Calibration and maintenance records for selected air samplers, composite water samplers, and environmental sample radiation measurement instrumentation

• Interlaboratory comparison program results

• Audits, self-assessments, reports, and corrective action documents related to the radiological environmental monitoring program since the last inspection

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one

(1) required sample as defined in Inspection Procedure 71124.07-05.

b. Findings

No findings were identified.

2RS08 Radioactive Solid Waste Processing, and Radioactive Material Handling, Storage, and Transportation (71124.08)

a. Inspection Scope

This area was inspected to verify the effectiveness of the licensees programs for processing, handling, storage, and transportation of radioactive material. The inspectors used the requirements of 10 CFR Parts 20, 61, and 71 and Department of Transportation regulations contained in 49 CFR Parts 171-180 for determining compliance. The inspectors interviewed licensee personnel and reviewed the following items:

• The solid radioactive waste system description, process control program, and the scope of the licensees audit program

• Control of radioactive waste storage areas including container labeling/marking and monitoring containers for deformation or signs of waste decomposition

• Changes to the liquid and solid waste processing system configuration including a review of waste processing equipment that is not operational or abandoned in place

• Radio-chemical sample analysis results for radioactive waste streams and use of scaling factors and calculations to account for difficult-to-measure radionuclides

• Processes for waste classification including use of scaling factors and 10 CFR Part 61 analysis

• Shipment packaging, surveying, labeling, marking, placarding, vehicle checking, driver instructing, and preparation of the disposal manifest

• Audits, self-assessments, reports, and corrective action reports radioactive solid waste processing, and radioactive material handling, storage, and transportation performed since the last inspection

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one

(1) required sample as defined in Inspection Procedure 71124.08-05.

b. Findings

Introduction.

The inspectors identified a Severity Level IV non-cited violation of 10 CFR Part 50.71, Maintenance of Records, because the licensee failed to update its Updated Final Safety Analysis Report (UFSAR) with submittals that include the effects of a change made to the facility. This finding was determined to be of very low safety significance.

Description.

While inspecting the licensees activities related to solid radwaste management and storage, the inspectors identified that the low level radwaste storage facility was not adequately described in Chapters 11 and 12 of the UFSAR. The licensee built the low level radwaste storage facility on the owner controlled area, outside of the protected area, for interim radwaste storage of dry active waste and solidified radioactive waste. Currently, the UFSAR, Chapters 11 and 12, Sections 11.4, Solid Waste Management, and 12.2.1, "Contained Radiation Sources," describe facilities for the storage of radioactive material, such as the dry active waste handling and spent resin handling system. Section 12.2.1.7 of the UFSAR also describes principal sources of radioactivity not enclosed by plant structures. This section included maximum activity inventory of different waste management system components, including the laundry tank, waste condensate tank, and spent resin tank. The low level radwaste storage facility was not described in the UFSAR in adequate detail.

The licensee is committed to Regulatory Guide 1.70, Standard, Format, and Content of a Safety Analysis Report, Revision 2, dated September 1975, which describes the

content of Chapter 11, Section 11.4, Solid Waste Management System. Regulatory Guide 1.70 states that this section should describe the capabilities of the plant to control, collect, handle, process, package, and temporarily store prior to shipment of solid radioactive waste generated as a result of normal operation, including anticipated operational occurrences. Regulatory Guide 1.70 also describes Chapter 12 of a safety analysis report and states, in part, that it should provide information on methods for radiation protection, estimated occupational radiation exposures to personnel during normal operation and anticipated operational occurrences, including radioactive material handling, processing, use, storage, and disposal. Section 12.2.1, Radiation Contained Sources, is the basis for the radiation protection design that should be described in the manner needed as input to the shield design calculations. Those sources that are contained in equipment like the radioactive waste management systems should be described. The source location in the plant should be specified so that all important sources of radioactivity can be located on plant layout drawings. Also, the UFSAR should provide a listing of isotope, quantity, form, and use of all sources that exceed 100 millicuries.

The low level radwaste storage facility has been in use since 1995 and contains a mixture of dry active waste and spent resin materials in separate storage compartments.

The 50.59 screening performed for this facility stated that the low level radwaste storage facility will have onsite storage space for a total of five years based on estimates of waste generation. This storage facility has been in operation for approximately 16 years.

The storage facility currently contains a significant source of radioactivity, 689.52 curies in total, which is not adequately described in the licensees UFSAR.

Analysis

. The performance deficiency associated with this finding was failure of the licensee to update the UFSAR to reflect changes made to the facility. This issue was dispositioned using traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. The finding is more than minor because it has a material impact on licensed activities in that stored radwaste materials with a significant radioactive source term has been relocated from the plant radiologically controlled area to the owner controlled area. In addition, the radwaste management program has been affected because the licensee was not originally licensed to act as a low level waste facility. However, the termination of the Barnwell Low Level Radioactive Waste Management facility has forced the licensee to build such a storage area and make changes to the facility, significantly increasing the onsite storage capacity. The inspectors determined that this finding did not reflect present performance because it is an issue with changes made to the facility more than 15 years previously. Therefore, there was no cross-cutting aspect associated with this finding.

Enforcement.

Title 10 CFR 50.71, Maintenance of Records, Section (e), requires, in part, that licensees periodically update their UFSAR with submittals that include the effects of all changes made in the facility or procedures as described in the UFSAR, and all safety analyses and evaluations performed by the licensee in support of conclusions that changes did not require a license amendment in accordance with 10 CFR 50.59(c)(2). Contrary to this requirement, from 1995 through the present, the licensee made changes to the facility, but failed to adequately update the UFSAR to

include these changes. Specifically, the licensee built the low level radwaste storage facility for storing dry radioactive waste and solidified radioactive waste outside of the protected area for an interim storage period and did not update the UFSAR to include this facility. Because the finding was a Severity Level IV violation and has been entered into the licensees corrective action program as condition report WF3-2011-07711. This finding is characterized as a Severity Level IV noncited violation in accordance with NRC Enforcement Policy, Section 6.1, and was treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy NCV 05000382/2011005-03, Failure to Periodically Update the UFSAR.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a.

The inspectors performed a review of the data submitted by the licensee for the third Quarter 2011 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

Inspection Scope

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b.

No findings were identified.

Findings

.2 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for the period from the fourth quarter 2010 through the third quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to Inspection Scope

determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one

(1) mitigating systems performance index - cooling water system sample as defined in Inspection Procedure 71151-05.

b.

Introduction.

The inspectors identified a non-cited violation of 10CFR50, Appendix B, Criterion III because the licensee did not translate applicable regulatory requirements and the design basis into specifications and instructions. Specifically, the licensee did not translate the design basis tornado event into a design calculation. This outage specific calculation was referenced by operations as the basis to ensure that the number of dry cooling tower (DCT) fans needed for decay heat removal remained available. As a result, additional analysis needed to be performed to verify that the ultimate heat sink (UHS) would have been able to perform its design function had a design basis tornado occurred during refueling outage RF-17.

Findings

Description.

In plant Modes 5 and 6, design calculation ECM-98-067, Limiting Single Failure Thermal-Hydraulic Analysis of Waterford 3 Spent Fuel Pool, Revision 1, requires all 15 DCT fans to be operable unless a condition-specific engineering change calculation has been completed to ensure that fewer fans are sufficient for the UHS heat removal requirements. Several operational procedures also require all 15 DCT fans be available unless the outage specific calculation has been completed. These procedures direct operators to reference the outage specific calculation to justify fewer than 15 fans.

During refuel outage RF-17, the licensee performed engineering change EC-24830 to determine the required number of DCT fans needed for each train. EC-24830 concluded that up to three DCT fans per train could be unavailable without impacting the DCTs ability to maintain cooling requirements. However, EC-24830 did not place any additional restrictions on fan unavailability during a tornado watch. Through calculation review, the inspectors recognized that if three of the missile-protected fans (9 of 15 fans are missile-protected) were unavailable (as allowed by EC-24830) and a design basis tornado occurred, the DCTs would potentially have only six fans available for cooling spent fuel. Since this condition had not been analyzed, compliance with EC-24830 could have placed the licensee in a condition where UHS heat removal capabilities would have been unknown and design basis requirements may not have been met.

Therefore, inspectors determined that the licensee failed to ensure that the design basis cooling requirements were properly translated into EC-24830.

The licensee conducted an analysis to show that UHS heat removal requirements would have been met with only six DCT fans available, therefore this non-cited violation has very low safety significance. Additional actions include incorporating tornado

consideration into the case specific calculations for DCT fan requirements during future refuel outages.

Analysis.

The failure to translate design basis into procedures and instructions is a performance deficiency. The inspectors determined that this issue was reasonably within the licensees ability to foresee and correct and should have been prevented. The performance deficiency is more than minor because it challenges the equipment performance attribute of the mitigating systems cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Since the calculation was used when the plant was shutdown, the inspectors used Manual Chapter 0609, Appendix G, "Shutdown Operations Significance Determination Process, and Appendix G, Attachment 1, "Shutdown Operations Significance Determination Process Phase 1 Operational Checklists." The issue was determined to have very low safety significance (Green)because it did not require a quantitative assessment. This finding had a cross-cutting aspect in the resources component of the human performance area in that the licensee did not incorporate accurate design information into instructions H.2(c).

Enforcement.

Title 10 of CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that the licensee ensures that the design basis is properly translated into specifications and instructions. Contrary to the above, from April 2011 to May 2011, the licensee did not translate the design basis tornado event into a design calculation used to determine the required number of DCT fans needed to operate the plant in Modes 5 and 6. The licensee completed a calculation that allowed less restrictive cooling requirements that could have allowed the site to enter an unanalyzed condition.

This condition existed during refuel outage 17. This violation was entered into the licensees corrective action program as CR-WF3-2011-6480, and actions taken to restore compliance included analysis of the condition and actions to ensure that future calculations include tornado analysis. This violation of Appendix B, Criterion III, is being treated as an NRC identified noncited violation, consistent with Section 2.3.2 of the Enforcement Policy: NCV 05000382/2011005-04, Failure to Translate Tornado Impact on the Ultimate Heat Sink During a Refueling Outage.

.3 Reactor Coolant System Specific Activity (BI01)

a.

On November 17, 2011, the inspectors sampled licensee submittals for the reactor coolant system specific activity performance indicator for the period from the fourth quarter 2010 through the third quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees reactor coolant system chemistry samples, technical specification requirements, issue reports, event reports, and NRC integrated inspection reports for the period from October 2010 through September 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator Inspection Scope

and none were identified. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one

(1) reactor coolant system specific activity sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.4 Reactor Coolant System Leakage (BI02)

a.

On November 17, 2011, the inspectors sampled licensee submittals for the reactor coolant system leakage performance indicator for the period from the fourth quarter 2010 through the third quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator logs, reactor coolant system leakage tracking data, issue reports, event reports, and NRC integrated inspection reports for the period from October 2010 through September 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one

(1) reactor coolant system leakage sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.5 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill and Exercise Performance, performance indicator for the period April 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.

Specifically, the inspectors reviewed licensee records and processes including

procedural guidance on assessing opportunities for the performance indicator; assessments of performance indicator opportunities during predesignated control room simulator training sessions, performance during the 2011 biennial exercise, and performance during other drills. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the drill/exercise performance sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.6 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspectors sampled licensee submittals for the Emergency Response Organization Drill Participation performance indicator for the period April 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator, rosters of personnel assigned to key emergency response organization positions, and exercise participation records. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the emergency response organization drill participation sample as defined in Inspection Procedure 71151-05.

b.

Finding

No findings were identified.

.7 Alert and Notification System (EP03)

a. Inspection Scope

The inspectors sampled licensee submittals for the Alert and Notification System performance indicator for the period April 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6,

was used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.

Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator and the results of periodic alert notification system operability tests. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the alert and notification system sample as defined in Inspection Procedure 71151-05.

c. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a.

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

Inspection Scope

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b.

No findings were identified.

Findings

.2 Daily Corrective Action Program Reviews

a.

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

Inspection Scope

The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b.

No findings were identified.

Findings

.3 Semi-Annual Trend Review

a.

On December 20, 2011, the inspectors performed a review of the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on repetitive equipment issues, but also considered the results of daily corrective action item screening discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human performance results. The inspectors nominally considered the 6-month period of June 2011 through December 2011 although some examples expanded beyond those dates where the scope of the trend warranted.

Inspection Scope

The inspectors also included issues documented outside the normal corrective action program in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the licensees corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

These activities constitute completion of one

(1) semi-annual trend inspection sample as defined in Inspection Procedure 71152-05.

b.

No findings were identified.

Findings

.4 Selected Issue Follow-up Inspection

a.

The inspectors performed an in-depth review of the licensees evaluation and corrective actions related to the failure of a pneumatic line used to close the main feedwater isolation valve (FW-184B). The inspectors reviewed the appropriateness of the assigned significance, the scope and depth of the causal analysis, and the timeliness of the resolution. The inspectors assessed whether the evaluation identified likely causes for the issues and identified appropriate corrective actions to address the identified causes.

The inspectors also conducted a review of the corrective actions to verify that appropriate measures were in place to prevent to prevent reoccurrence of the issue. In addition, the inspectors assessed whether the licensees evaluation considered extent of condition, generic implications, common cause, and previous occurrences. The inspectors reviewed the potential impact on nuclear safety and risk to verify that the licensee had taken corrective actions commensurate with the significance of the issue.

The inspectors evaluated these actions against the requirements of the licensees corrective action program and performance attributes contained in IP 71152, Section 03.06.

Inspection Scope

These activities constitute completion of one

(1) in-depth problem identification and resolution sample as defined in Inspection Procedure 71152-05.

b.

Introduction.

The inspectors identified a non-cited violation of Technical Specification 6.8.1.a because the licensee did not follow work order instructions to install a pressure gage in an air line used to measure and maintain pressure for the hydraulic accumulators that close the main feedwater isolation valve. Specifically, the licensee did not follow the instructions to assemble and tighten a Swagelok fitting according to the work order. As a result, the fitting failed, preventing the valve from being able to perform its safety-related function.

Findings

Description.

In 2005, a plant modification installed a pressure gauge in the main feedwater isolation valve nitrogen line to provide visual indication of accumulator pressure. In 2010, one of the Swagelok fittings used for the installation failed. The licensee replaced the fitting and performed an extent of condition review. Two other fittings that did not meet the manufacturers tightness specifications were identified, but no additional actions were taken. Initial examination of the failed fitting showed that it had not been correctly assembled and tightened, but no evaluation as to when or how the deficiency occurred was performed. The fitting failure was essentially treated as a broke/fix condition.

The inspectors reviewed Work Order 61044, which provided instructions on installing the modification. Section 5.1 of that work order provided specific instructions on how to assemble and tighten a Swagelok fitting, as well as verify that the fitting was assembled correctly, post installation. Based on this review, the inspectors concluded that the

technicians did not follow the installation and verification instructions provided in the work order.

The inspectors also questioned the operability of the two fittings discovered during the extent of condition review. Subsequent licensee review of the condition determined that despite failing the manufacturers go-no go gap test, the fittings were sufficiently tight to preclude a similar failure. The licensee also reclassified the fitting failure as a condition adverse to quality and performed an apparent cause determination for the failure.

A review of the safety analysis showed that a failure of the main feedwater isolation valve to close on demand would have very low safety significance since other valves, such as the feedwater regulating valve, would have closed to isolate an affected steam generator. The licensee entered this condition into the corrective action program as CR-WF3-2010-1166 and CR-WF3-2011-7469. Corrective actions included repairing the Swagelok fitting and completing an apparent cause evaluation to determine the nature of the fitting failure and the failure to follow procedure.

Analysis.

The failure to follow work order instructions is a performance deficiency. The inspectors determined that this deficiency is reasonable for the licensee to be able to foresee and correct and could have been prevented. This performance deficiency is more than minor because it affects the equipment performance attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspector performed the initial significance determination for the main feedwater isolation valve failure using NRC Inspection Manual 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. The finding screened to a Phase 2 significance determination because it involved a potential loss of one train of safety related equipment for longer than the technical specification allowed outage time. A Region IV senior reactor analyst performed a Phase 2 significance determination and used the pre-solved worksheet from the Risk Informed Inspection Notebook for the Waterford-3 Nuclear Power Plant, Revision 2.01a. However, the main feedwater isolation valves were not included in the pre-solved worksheet and the valves did not appear as components in the Phase 2 significance determination worksheets. The senior reactor analyst performed a Phase 3 significance determination for this issue.

The analyst noted that the main feed isolation valves were not a significant contributor to core damage frequency and were not included in the NRCs SPAR model. These valves close to mitigate core overcooling events or to isolate feedwater flow to a ruptured feedwater line inside containment. Over cooling events do not lead to core damage. A ruptured feedwater line could challenge containment integrity, but without core damage there would be no potential for a large early release. If a valve failed to close on demand, the licensee had other means to isolate feedwater flow to a steam generator or into containment. Operators could secure feedwater pumps, close a block valve, or close the main feedwater flow control valves. Accordingly, the contribution to core damage was much less than E-6. As a result, this finding had very low safety significance (Green). This finding does not have a crosscutting aspect since it is not indicative of current plant performance.

Enforcement.

Technical specification 6.8.1.a states that written procedures shall be established, implemented, and maintained as recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Appendix A, Section 9, Procedures for Performing Maintenance, states, in part, that maintenance that can affect the performance of safety-related equipment should be performed in accordance with procedures on documented instructions. Contrary to the above, in 2005, the licensee failed to comply with the instructions provided in Work Order 61044, for assembly and tightening a Swagelok fitting during the installation of a pressure gauge to the main feedwater isolation valve hydraulic accumulators. This condition existed since the pressure gauge was installed in 2005, until discovery and repair in 2010. This violation was entered into the licensees corrective action program as CR-WF3-2010-1166 and CR-WF3-2011-7469. Corrective actions included repairing the Swagelok fitting and completing an apparent cause evaluation to determine the nature of the fitting failure and failure to follow procedure. This violation of technical specification 6.8.1.a is being treated as an NRC identified non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy: NCV 05000382/2011005-05, Failure to Follow Work Order Instructions to Install a Swagelok Fitting on a Main Feedwater Isolation Valve Tube Connection.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report (LER) 05000382/2009-006-00, Degraded Hydraulic

Fluid Causes Both Main Feedwater Isolation Valves to Fail

On October 22, 2009, both main feedwater isolation valves failed to close in the required time period during the performance of a surveillance test. At the time, the licensee determined that the most probable cause was gelling of the hydraulic fluid due to an introduction of moisture in the lines. As a part of the review for this event, the inspectors identified a non-cited violation 05000382/2011005-01, Failure to Identify and Correct a Condition Adverse to Quality Associated with the Main Feedwater Isolation Valves. The inspectors documented this violation in Section 1R12 of this report. This licensee event report is closed.

.2 (Closed) Licensee Event Report 05000382/2011-002-00, Main Feedwater Isolation Valve

A Failed Surveillance Requirement

On April 7, 2011, the main feedwater isolation valve for train A failed to close in the required time period during the performance of a surveillance test. The cause of the failure was due to varnish deposits on the interior surface of the valve that prevented the valve from stoking close. As a part of the review for this event, the inspectors identified a non-cited violation 05000382/2011005-01, Failure to Identify and Correct a Condition Adverse to Quality Associated with the Main Feedwater Isolation Valves. The inspectors documented this violation in Section 1R12 of this report. This licensee event report is closed.

.3 (Closed) Licensee Event Report 05000382/2010-002-00, Main Feedwater Isolation

Valve B Exceeded Allowed Outage Time Due to Tubing Rupture

On February 23, 2010, the tubing connection on the main feedwater isolation valve failed shortly after performing a calibration test on its nitrogen accumulator pressure switch.

The cause of the failure was due to a loose Swagelok fitting. As a part of the review of this event, the inspectors identified a non-cited violation 05000382/2011005-05, Failure to Follow Work Order Instructions to Install a Swagelok Fitting on a Main Feedwater Isolation Valve Tube Connection. The inspectors documented this violation in Section 4OA2 of this report. This licensee event report is closed.

.4 (Closed) Licensee Event Report 05000382/2011-003-00, Emergency Diesel Generator

Output Breaker Failed to Automatically Close

On April 30, 2011, the train A emergency diesel generator output breaker failed to automatically close as expected during the performance of a surveillance test. The cause of the failure was due to an improperly wired time delay relay. As a part of the review of this event, the inspectors identified a non-cited violation 05000382/2011003-03, Failure to implement written procedures for restoring a time delay relay associated with the train A emergency diesel generator output breaker. The inspectors documented this violation in inspection report 05000382/2011003. This licensee event report is closed.

4OA5 Other Activities

.1 a.

(Closed) NRC Temporary Instruction (TI) 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01)

The inspectors verified that the onsite documentation, system hardware, and licensee actions were consistent with the information provided in the licensees response to NRC Generic Letter (GL) 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. Specifically, the inspectors verified that the licensee has implemented or was in the process of implementing the commitments, modifications, and programmatically controlled actions described in the licensees response to GL 2008-01. The inspection was conducted in accordance with Temporary Instruction 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01), and considered the site-specific supplemental information provided by the Office of Nuclear Reactor Regulations to the inspectors.

Inspection Scope b.

The selected temporary instruction areas of inspection were licensing basis, design, testing, and corrective actions. In general, the licensees actions taken in response to GL 2008-01 were adequate to address the potential for the accumulation of Inspection Documentation

unacceptable gas volumes in emergency core cooling systems pump suction and discharge piping. The inspectors verified that issues identified during the licensees reviews and walkdowns of emergency core cooling systems were entered in the corrective action program and were being addressed. The inspectors determined that the proposed or implemented corrective actions were adequate to ensure that deficiencies related to emergency core cooling systems gas accumulation were corrected. Specifically, the replacement of all the safety injection tank check valves in an upcoming refueling outage with another type that isnt as susceptible to leaking should resolve, by design, the introduction of gas into the low pressure safety injection system. The documentation of the inspection effort and any resulting observations are below.

Licensing Basis: The inspectors reviewed selected portions of licensing basis documents to verify that they were consistent with the Office of Nuclear Reactor Regulation assessment report and that the licensee properly processed any required changes. The inspectors reviewed selected portions of technical specifications, technical specification bases, and the updated final safety analysis report. The inspectors also verified that applicable documents that described the plant and plant operation, such as calculations, piping and instrumentation diagrams, procedures, and corrective action program documents addressed the areas of concern and were changed, if needed, following plant changes. The inspectors confirmed that the licensee performed surveillance tests at the frequency required by the technical specifications.

The inspectors verified that the licensee tracked their commitment to evaluate and implement any changes that will be contained in the technical specification task force traveler.

Design The inspectors verified that the licensee had established void acceptance criteria consistent with the void acceptance criteria identified by the Office of Nuclear Reactor Regulation. The inspectors also confirmed that the range of flow conditions evaluated by the licensee was consistent with the full range of design basis and expected flow rates for various break sizes and locations.

The inspectors reviewed design documents, performed system walkdowns, and interviewed plant personnel to verify that the licensee addressed design and operating characteristics of the emergency core cooling systems. The inspectors verified that the licensee had identified the applicable gas intrusion mechanisms for their plant.

The inspectors reviewed documents, including calculations, and engineering evaluations with respect to gas accumulation in the emergency core cooling systems, decay heat removal, and containment spray systems. The inspectors verified that these documents addressed venting requirements, aspects where pipes were normally voided such as some containment spray piping inside containment, void control during maintenance activities, and the potential for vortex effects that could ingest gas into the systems during design basis events.

The inspectors conducted a walkdown of selected regions of the safety injection system and containment spray system in sufficient detail to assess the licensees walkdowns.

The inspectors also verified that the information obtained during the licensees walkdown

was consistent with the items identified during the inspectors independent walkdown.

The inspectors completed portions of a full system alignment inspection of the safety injection system in an earlier inspection period. The inspectors documented additional activities that counted towards the completion of this temporary instruction in Section 4OA5 of Inspection Reports 05000382/2011003.

The inspectors verified that piping and instrumentation diagrams and isometric drawings that describe the safety injection system configurations. The review of the selected portions of isometric drawings considered the following:

• High point vents were identified;

• High points without vents were recognizable;

• Other areas where gas could accumulate and potentially impact operability, such as at orifices in horizontal pipes, isolated branch lines, heat exchangers, improperly sloped piping, and under closed valves, were described in the drawings or in referenced documentation;

• Horizontal pipe centerline elevation deviations and pipe slopes in nominally horizontal lines that exceed specified criteria were identified;

• All pipes and fittings were clearly shown; and

• The drawings were up-to-date with respect to recent hardware changes, and that any discrepancies between as-built configurations and the drawings were documented and entered into the corrective action program for resolution.

The inspectors verified that the licensee had completed their walkdowns and selectively verified that the licensee identified discrepant conditions in their corrective action program and appropriately modified affected procedures and training documents.

Testing: The inspectors reviewed selected surveillance, post-modification test, and post-maintenance test procedures and results to verify that the licensee has approved and was using procedures that were adequate to address the issue of gas accumulation and/or intrusion in the subject systems. This review included the verification of procedures used for conducting surveillances and determination of void volumes to ensure that the void criteria was satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance. Also, the inspectors reviewed procedures used for filling and venting following conditions which may have introduced voids into the subject systems to verify that the procedures addressed testing for such voids and provided processes for their reduction or elimination. The inspectors also reviewed selected portions of procedures used during the surveillance testing of the low pressure safety injection system. Specifically, the inspectors observed the performance of a fill and vent surveillance on a new equalizing line (Valve SI-4052A/B). SI-4052A/B was installed as a result of a design change to prevent void formation in the low pressure safety injection system during a transition to shutdown cooling. This additional activity

counted towards the completion of this temporary instruction and was documented in Inspection Report 05000382/2011003.

Corrective Actions Based on this review, the inspectors concluded that there is reasonable assurance that the licensee will complete all outstanding items and incorporate this information into the design basis and operational practices. This temporary instruction is closed.

The inspectors reviewed the corrective action program documents to assess how effectively the licensee addressed the issues in the corrective action program associated with Generic Letter 2008-01. In addition, the inspectors verified that the licensee implemented appropriate corrective actions for selected corrective actions identified in the nine-month and supplemental responses. The inspectors determined that the licensee had effectively implemented the actions required by Generic Letter 2008-01.

c.

No findings were identified.

Findings

4OA6 Meetings

Exit Meeting Summary

On November 17, 2011, the inspectors presented the results of the radiation safety inspections to Ms. K. Cook, General Manager, Plant Operations, and other members of the licensee staff.

The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On December 9, 2011, the inspector presented the onsite emergency preparedness inspection results to Ms. D. Jacobs, Vice President, Operations, and other members of her staff, who acknowledged the results. The inspector confirmed that proprietary, sensitive, or personal information examined during the inspection had been returned to the identified custodian.

On December 15, 2011, the inspectors presented the preliminary inspection results of the heat sink inspection to Ms. D. Jacobs, Vice President, Operations, and other members of the licensee staff. A final exit meeting was presented to W. Steeleman, Licensing Manager, on January 5, 2012. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On January 19, 2012, the inspectors presented the inspection results to Mr. K. Nichols, Director, Engineering, and other members of the licensee staff. Mr. Nichols was acting as Site Vice President of Operations. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section 2.3.2 of the NRC Enforcement Policy, for being dispositioned as a non-cited violation.

Title 10 of CFR 50.54(q) requires, in part, that a holder of a nuclear power reactor operating license shall follow emergency plans which meet the standards in 10 CFR 50.47(b) and 10 CFR 50, Appendix E. Revision 28 of the Waterford 3 Emergency Plan, Section 8.1.1.3, requires that initial and periodic refresher training be provided to various categories of emergency personnel, including those who perform duties on first aid and rescue teams. The Waterford Emergency Plan specifies that periodic refresher training will be provided on an annual basis at a minimum. This requirement is stated in order to implement the requirements of 10 CFR 50.47(b)(15). Contrary to this requirement, the licensee identified that first aid periodic refresher training was being conducted on a two-year cycle, and periodic refresher training for rescue teams were not being provided.

The finding was of very low safety significance because it did not result in emergency response personnel not being available to provide continuous coverage (24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) for a key Emergency Response Organization function (as defined in NEI 99-02).

The finding was entered in the licensees corrective action program as Condition Report CR-WF3-2010-4468.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Entergy Personnel

D. Jacobs, Vice President, Operations

K. Cook, General Manager, Plant Operations

S. Adams, Director, Nuclear Safety Assurance

C. Alday, Manager, System Engineering

E. Begley, Senior Engineer, Programs and Components

D. Boan, Supervisor, Radiation Protection

E. Brauner, Supervisor, System Engineering

J. Brawley, ALARA Supervisor, Radiation Protection

A. Buford, Engineer II, System Engineering

L. Dauzat, Operations Supervisor, Radiation Protection

C. England, Manager, Radiation Protection

G. Fey, Manager, Emergency Planning

C. Fugate, Assistant Manager, Operations

R. Gilmore, Manager, Engineering

J. Gumnick, Manager, Radiation Protection

J. Hashim, Senior Engineer, Programs and Components

M. Haydel, Supervisor, Programs and Components

J. Hornsby, Manager, Chemistry

J. Houghtaling, Senior Project Manager

B. Lanka, Manager, Design Engineering

B. Lindsey, Manager, Maintenance

M. Mason, Senior Licensing Specialist, Licensing

W. McKinney, Manager, Corrective Action and Assessments

D. Miller, Supervisor, Radwaste and Radioactive Material Control

D. Moor, Fleet Manager, Radiation Protection

K. Nichols, Director, Engineering

R. OQuinn, Steam Generator Program

R. Perry, Senior Emergency Planner

A. Piluti, Manager, Radiation Protection

R. Putnam, Manager, Programs and Components

T. Qualantone, Manager, Plant Security

W. Steelman, Manager, Licensing

J. Williams, Senior Licensing Specialist, Licensing

NRC Personnel

C. Smith, Project Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000382/2011005-01 NCV Inoperable Train of Containment Cooling System (Section 1R07)

05000382/2011005-02 NCV Failure to Identify and Correct a Condition Adverse to Quality Associated with the Main Feedwater Isolation Valves (Section 1R12)

05000382/2011005-03 NCV Failure to Periodically Update the Updated Final Safety Analysis Report (Section 2RS08)

05000382/2011005-04 NCV Failure to Translate Tornado Impact on the Ultimate Heat Sink During a Refueling Outage (Section 4OA1.2)

05000382/2011005-05 NCV Failure to Follow Work Order Instructions to Install a Swagelok Fitting on a Main Feedwater Isolation Valve Tube Connection (Section 4OA2.4)

Closed

05000382/2009-006-00 LER Degraded Hydraulic Fluid Causes Both Main Feedwater Isolation Valves to Fail (Section 4OA3.1)

05000382/2010-002-00 LER Main Feedwater Isolation Valve B Exceeded Allowed Outage Time Due to Tubing Rupture (Section 4OA3.3)

05000382/2011-002-00 LER Main Feedwater Isolation Valve A Failed Surveillance Requirement (Section 4OA3.2)

05000382/2011-003-00 LER Emergency Diesel Generator Output Breaker Failed to Automatically Close (Section 4OA3.4)

2515/177 TI Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01) (Section 4OA5)

LISTS OF