IR 05000313/2011005

IR 05000313-11-005, 05000368-11-005, on October 1 Through December 31, 2011, Arkansas Nuclear One

ML120450828
Person / Time
Site:	Arkansas Nuclear
Issue date:	02/14/2012
From:	Allen D B NRC/RGN-IV/DRP/RPB-E
To:	Schwarz C J Entergy Operations
References
IR-11-005
Download: ML120450828 (67)

Text

February 14, 2012

Christopher J. Schwarz, Site Vice President Arkansas Nuclear One Entergy Operations, In SR 333 Russellville, AR 72802

-0967

SUBJECT: ARKANSAS NUCLEAR ONE

- NRC INTEGRATED INSPECTION REPORT NUMBER 05000313/2011005 AND 05000368/2011005 Dear Mr. Schwarz

On December 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Arkansas Nuclear One facility Units

, 1 and The enclosed inspection report documents the inspection results which were discussed on January 20, 2012, with Mr. M. Chisum, General Manager, Plant Operations

, and other members of your staf The inspections examined activities conducted under your license as they relate to safety and compliance with the Commission

's rules and regulations and with the conditions of your licens The inspectors reviewed selected procedures and records, observed activities, and interviewed personne T wo NRC identified and four self-revealing findings of very low safety significance (Green) were identified during this inspectio Five of these findings were determined to involve violations of NRC requirement Further, t wo licensee-identified violations which were determined to be of very low safety significance are listed in this repor The NRC is treating these violations as noncited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Polic If you contest these noncited 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 Arkansas Nuclear On 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 Arkansas Nuclear On 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 U N I T E D S T A T E S N U C L E A R R E G U L A T O R Y C O M M I S S I O N R E G I O N I V1600 EAST LAMAR BLVD A R L I N G T O N , T E X A S 7 6 0 1 1-4511 C. Schwarz 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, Branch Chief Project Branch E Division of Reactor Projects Docket Nos:

0 50 00 313, 0 50 00 368 License Nos:

D PR-51, NPF-6

Enclosure:

Inspection Report 05000313/2011005 and 05000 368/2011005 w/

Attachment:

Supplemental Information cc w/ encl: Electronic Distribution

SUMMARY OF FINDINGS

IR 05000313/2011005

05000368/2011005; 10/1/2011-12/31/2011; Arkansas Nuclear One Integrated Resident and Regional Report; Operability Evaluations and Functionality Assessments;

Refueling and Other Outage Activities;

Problem Identification and Resolution.

The report covered a 3

-month period of inspection by resident inspectors and announced baseline inspection s by region-based inspector s. Five Green noncited violations of significance were 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 cross-cutting aspect is determined using Inspection Manual Chapter 0310, "Components Within the Cross Cutting Areas." Findings for which the significance determination proces s 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 noncited violation of Unit 1 Technical Specification 3.8.4, "DC Sources-Operating," Technical Specification 3.8.7, "Inverters- Operating," and Technical Specification 3.8.9, "Distribution Systems-Operating," due to the licensee's failure to complete the associated required action prior to the specified completion time while the associated emergency switchgear room chillers were out of service for planned maintenance. The licensee immediately implemented corrective action s to direct Operations to enter the applicable technical specifications and notify ANO management. The issue was identified to the licensee and entered into their corrective action program as Condition Report CR

-ANO-1-2012-0043. The inspectors determined that not completing the required actions for the applicable technical specifications prior to the specified completion time while the associated emergency switchgear room chillers were out of service for planned maintenance is a performance deficiency. The performance deficiency is determined to be more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and adversely affect s the associated cornerstone objective to ensure availability, reliability, and the capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. Specifically, on December 7, 2011, the failure to complete the required actions prior to the specified completion times for Technical Specification 3.8.4, "DC Sources- Operating," Technical Specification 3.8.7, "Inverters- Operating, and Technical Specification 3.8.9, " Distribution Systems - Operating," after removing the VCH

-4 A from service for maintenance was a violation of technical specifications. Additionally , on December 19, 2011

, the failure to complete the required actions prior to the specified completion time for Technical Specification 3.8.7, "Inverters- Operating ," after removing the

VCH-4 B from service for maintenance

, was a violation of technical specifications. Using Inspection Manual Chapter 0609.04, "Phase 1

- Initial Screening and Characterization of Findings," the finding was determined to require a Phase 2 analysis because removing each VCH

-4 chiller from service in December 2011 did result in an actual loss of safety function of a single train for greater than its technical specification allowed completion time. A phase 2 analysis from a previous noncited violation that bounds this issue determined the finding to be of very low safety significance (Green). Specifically, although the function was lost by the designated support equipment (emergency switchgear chillers), the licensee had an evaluation that credited compensatory measures and specific environmental conditions that assured the overall functionality of the applicable switchgear train was not lost. The finding was determined to have a cross-cutting aspect in the area of human performance, associated with the decision making component, in that 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 that it is unsafe in order to disapprove the action H.1(b) (Section 1R15)

.

Green.

The inspectors documented a self-revealing, noncited violation of 10 CFR 50 Appendix B, Criterion XVI, "Corrective Action," for the licensee's failure to promptly identify and correct a condition adverse to quality associated with degradation of the protective wrap (brand name- Denso) installed on the Unit 1 service water pump columns. The Denso protective wrap around the P

-4C service water pump suction column became unraveled and was drawn into the pump suction while running and caused high differential pressure across the pump discharge strainer. The licensee took immediate corrective action to secure the pump and then removed the Denso protective wrap from all pump columns in the Unit 1 service water intake structure bays. Unit 2 does not have Denso protective wrap installed on their service water pumps. The licensee has entered this issue into their corrective action program as Condition Report CR-ANO-1-2011-2843. The failure to promptly identify and correct the observed degradation of the protective wrap installed on the Unit 1 service water pump columns is determined to be a performance deficiency. The performance deficiency is determined to be more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affect s the cornerstone objective to ensure availability, reliability, and the capability of systems that respond to initiating events to prevent undesirable consequence s and is therefore a finding. The inspectors performed the significance determination for the failure of service water pump 4C using NRC Inspection Manual Chapter 0609, Attachment 0609.04, "Phase 1

- Initial Screening and Characterization of Findings." The problem had occurred during an outage, but it could have occurred at power during a system realignment. The at-power model was more conservative, so it was used to evaluate the finding. Service water was a two train system with a swing pump (an installed spare). The allowed outage time for one train was 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Operators could easily align the swing pump to provide the train B service water loads within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Therefore, this finding screened to Green because: 1) it was not a design or qualification deficiency; 2) it did not result in loss of safety function of one train of equipment for more than its technical specification allowed outage time; 3) It did not result in a loss of one train of non-technical specification equipment; and 4) it did not screen as potentially risk significant due to an external event.

The finding was determined to have a cross-cutting aspect in the area of problem identification and resolution, associated with the corrective action program component in that the licensee failed to thoroughly evaluate the degraded protective wrap such that the resolutions addressed causes and extent of conditions, to include operability of the service water pump

P.1(c) (Section 1R20.2).

Green.

The inspectors documented a self revealing, noncited violation of Unit 1 Technical Specification 5.4.1.a for the failure to implement station procedure OP-1015.049 "Configuration Control Program", Revision 1. Specifically, on multiple occasions, station personnel failed to maintain configuration control through the use of valve line-ups and station procedures to ensure reactor plant components were in required positions. In each specific example the licensee took action to place the applicable system in a safe configuration. The licensee is implementing long term programmatic corrective actions. The licensee has placed that issue into their corrective action program as Condition Report CR-ANO-C-2011-2942. The failure of station personnel to maintain configuration control through the use of valve line-ups and governing station procedures is a performance deficiency.

The performance deficiency is more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affect s the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. Using Manual Chapter 0609.04, "Phase 1

- Initial Screening and Characterization of Findings," the examples included an actual loss of safety function of a non-technical specification train of equipment designated as risk-significant per 10CFR50.65, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A Phase 3 significance determination analysis was performed by a Region IV senior reactor analyst. The dominant core damage sequences for Unit 1 were station blackouts with battery depletion and transients with loss of feedwater and feed and bleed capability. The dominant core damage sequences for Unit 2 were station blackout with loss of emergency feedwater and once-through-cooling, loss of 4160 volt vital bus 2A4 with loss of feedwater and once-through-cooling, and station blackout with an 8-hour battery depletion. Based on both units having the capability to operate a steam driven emergency feedwater pump during the dominate core damage sequences the finding was determined to have very low safety significance (Green). The finding was determined to have a cross-cutting aspect in the area of human performance, associated with the work practices component in that the licensee failed to define and effectively communicate expectations regarding procedural guidance and personnel follow procedures when performing component positioning H.4(b)

(Section 4OA2.

4).

Cornerstone: Barrier Integrity

Green.

The inspectors documented a self-revealing, noncited violation of Uni t 1 Technical Specification 5.4.1.a for the failure to implement station procedure OP-1104.006 "Spent Fuel Cooling System", Revision 51. Specifically, SF

-10, flow control to purification loop valve, was found 3 turns open when it was required to be closed. This resulted in the spent fuel pool level lowering by 0.6 feet, which was below procedural limits, when the fuel transfer canal was placed in purification and SF

-45, transfer tube isolation valve, was closed to support diving operations in the Unit 1 spent fuel pool tilt pit. After receiving the spent fuel pool low level alarm, operations personnel secured purification, and opened SF-45 which allowed water level to return to normal. Additional actions taken by the licensee included identifying that SF-10 require s a torque amplifying device to operate. The issue was entered into the licensee's corrective action program as Condition Report CR

-ANO-1-2011-2498. The failure of operations personnel to follow the requirements of procedure

OP-1104.006 and close SF

-10 prior to initiating fuel transfer canal on purification, which resulted in an unexpected loss of approximately 4500 gallons of water from the spent fuel pool, is a performance deficiency.

The performance deficiency is more than minor because it is associated with the configuration control attribute of the Barrier Integrity cornerstone and adversely affect s the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events and is therefore a finding. Using Manual Chapter 0609.04, "Phase 1

- Initial Screening and Characterization of Findings," the finding was determined to have very low safety significance (Green) because the finding did not result in the loss of spent fuel cooling, did not result from fuel handling errors that caused damage to the fuel clad integrity or a dropped assembly and did not result in a loss of spent fuel inventory of greater than 10 percent of the spent fuel poo l volume. The finding was determined to have a cross-cutting aspect in the area of human performance, associated with the work control component in that the licensee failed to ensure that work activities were appropriately coordinated to support long term equipment reliability by limiting operator work-arounds when a torque amplifying device was required to shut SF

-10 H.3(b) (Section 1R20.1

).

Green.

The inspectors identified a noncited violation of 10 CFR 50, Appendix B, Criterion XVI for failure to identify and correct a condition adverse to quality.

Specifically, on November 1, 2011, the licensee failed to identify and correct a condition associated with seating an irradiated fuel bundle into a reactor building storage location during core re-loading activities. The licensee failed to thoroughly evaluate a discrepancy associated with an unexpected vertical measurement when inserting an irradiated fuel bundle prior to unlatching the fuel bundle. This resulted in the bundle dropping 1 1/8 inches when the licensee attempted to retrieve it. After the bundle dropped, the licensee immediately performed a visual inspection and

, with vendor analysis support

, removed the bundle from service. The licensee entered this issue into the corrective action program as Condition Report CR

-ANO-1-2012-0110. The failure to identify and correct the discrepancy in the vertical position of an irradiated fuel bundle during fuel handling operations is a performance deficiency

. The performance deficiency is determined to be more than minor because it is associated with the human performance attribute of the Barrier Integrity cornerstone and adversely affect s the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the performance deficiency resulted in a dropped fuel bundle that was subsequently removed from service due to possible fuel pellet damage. The event also took place while the reactor building was open to the atmosphere. Using Manual Chapter 0609, Appendix G, Attachment 1, Checklist 4, "PWR Refueling Operation: RCS Level >23'," the finding was determined to have very low safety significance (Green) because the finding did not adversely affect:

1) core heat removal, 2)inventory control, 3) electrical power, 4) containment control, or 5) reactivity control. The finding was determined to have a cross-cutting aspect in the area of human performance, associated with decision making component in that the licensee failed to use conservative assumptions and adopt a requirement to demonstrate that the proposed action is safe in order to proceed when deciding to accept the discrepancy in the vertical measurement when storing a fuel bundle in the reactor building storage rack H.1(b) (Section 1R20.3

).

Green.

The inspectors documented a self-revealing finding for the failure to take adequate corrective actions for known deficiencies associated with the Unit 1 fuel transfer system. Specifically, the licensee failed to investigate and correct issues that had been identified by site and vendor personnel from 1996 through 2010. This led to repeated fuel transfer system failures and significant core offload and reload delays during the 1R23 refueling outage, which placed the plant in an unplanned configuration for an extended period of time. After the failure of the fuel transfer equipment, multiple corrective actions were performed which included the installation of a temporary modification which allowed fuel movement to continue to support core reloading. The issue was entered into the licensee's corrective action program as Condition Report CR

-ANO-1-2011-2558. The failure of the licensee to take effective corrective action for known deficiencies related to the Unit 1 fuel transfer system is determined to be a performance deficiency. The performance deficiency is determined to be more than minor because

, if left uncorrected

, the performance deficiency could become a more safety significant issue. Specifically, the continued failure of the licensee to correct known deficiencies in the fuel transfer system could lead to damage to a fuel bundle. Using Manual Chapter 0609, Appendix G, Attachment 1, Checklist 4, "PWR Refueling Operation: RCS Level >23'," the finding was determined to have very low safety significance (Green) because the finding did not adversely affect: 1) core heat removal, 2) inventory control, 3) electrical power, 4) containment control, or 5)reactivity control. The finding was determined to have a cross-cutting aspect in the area of human performance, associated with decision making component in that the licensee failed to use conservative assumptions 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 decision making efforts affecting the fuel transfer system did not reflect a safety minded culture as past experience and vendor recommendations were disregarded

H.1(b) (Section 1R20.4)

.

B. Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 began the period at 93 percent reactor power in coastdown to refueling outage 1R23. On October 16, 2011, Unit 1 entered Mode 3 to begin refueling outage 1R23. On November 22, 2011, Unit 1 closed the main generator breaker to end refueling outage 1R23. On November 26, 2011, Unit 1 reached 100 percent reactor power and remained there for the remainder of the period.

Unit 2 began the period at 100 percent reactor power. On December 20, 2011, Unit 2 reduced power to 47 percent reactor power due to securing the 2P

-8A heater drain pump and to address a main condenser tube leak that was causing high sodium levels above 50 ppb in both steam generators. On December 21, 2011, Unit 2 raised power to 80 percent reactor power after returning the 2P-8A heater drain pump to operation. On December 22, 2011, following repair of the condenser tubes, Unit 2 reached 100 percent reactor power and remained there for the remainder of the period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrit y

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. The inspectors performed a review of the adverse weather procedures for seasonal extreme low temperature preparations. The inspectors verified that weather

-related equipment deficiencies identified during the previous year were corrected prior to the onset of seasonal extremes, and evaluated the implementation of the adverse weather preparation procedures and compensatory measures for the affected conditions before the onset of, and during, the adverse weather conditions.

Inspection Scope

During the inspection, the inspectors focused on plant

-specific design features and the procedures used by plant personnel to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Safety Analysis Report (SAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant

-specific procedures. Specific documents reviewed during this inspection are listed in the attachment. The inspectors also reviewed corrective action program items to verify that plant personnel were identifying adverse weather issues at an appropriate threshold and entering them into thei r corrective action program in accordance with station corrective action procedures. The inspectors' reviews focused specifically on the following plant systems:

Unit 1 and Unit 2 emergency diesel generator fuel storage vaults Unit 1 and Unit 2 service water intake structures Unit 2 refuel water tank and Unit 1 borated water storage tank These activities constitute completion of one (1) readiness for seasonal adverse weather sample as defined in Inspection Procedure 71111.01-05. b. No findings were identified.

Findings

1R04 Equipment Alignments

.1 Partial Walkdown

a. The inspectors performed partial system walkdowns of the following risk

-significant systems: Inspection Scope October 18, 2011, Unit 1 spent fuel pool cooling with temporary power modification October 19, 2011, Unit 2 service water bay A and bay C while bay B and the emergency cooling pond were unavailable November 2, 2011, alternate AC diesel generator and Unit 1 emergency diesel generator 2 while emergency diesel generato r 1 was out of service for maintenance 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, SAR, 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 three (3) partial system walkdown sample s a s defined in Inspection Procedure 71111.04-05.

b. No findings were identified.

Findings

.2 Complete Walkdown

a. On December 22, 2011 , the inspectors performed a complete system alignment inspection of the Unit 2 fire water system to verify the functional capability of the system. The inspectors selected this system because it was considered both safety significant and risk significant in the licensee's probabilistic risk assessment. The inspectors inspected the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment

-alignment problems were being identified and appropriately resolved. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope These activities constitute completion of one (1) complete system walkdown sample 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 October 17, 2011, Unit 1, Fire Zone FZ-1063 through FZ

-1067 north and south , reactor building October 18, 2011, Unit 1, Fire Zone FZ

-1030, service water intake structure during hot work December 30, 2011, Unit 2, Fire Zone 2200-MM , electrical switchgear, feedwater heaters and turbine area, elevation 386 December 30, 2011, Unit 2 , Fire Zone 2076-HH , electrical equipment (motor generator set

) room 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 licensee's fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's 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 plant's 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 licensee's 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 sample s as defined in Inspection Procedure 71111.05-05. b. No findings were identified.

Findings

1R06 Flood Protection Measures

a. The inspectors reviewed the SAR, 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 December 19, 2011, Unit 1 and 2 emergency diesel generator fuel oil storage vaults during fire water deluge actuation December 22, 2011, manhole MH

-9 and manhole MH

-10,which contain two trains of Unit 1 emergency diesel generator fuel oil transfer pump electrical power, and manhole MH

-4, which contains two trains of Unit 1 service water electrical power cables December 30, 2011, Unit 1 west decay heat vault These activities constitute completion of two (2) flood protection measures inspection sample s and 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 Unit 1 train B decay heat system heat exchanger

. 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 licensee's heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was 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.

Inspection Scope These activities constitute completion of one (1) heat sink inspection sample as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

R08 Inservice Inspection Activities

.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water Reactor Vessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control (71111.08-02.01)

a. The inspectors observed 16 nondestructive examination activities and reviewed five nondestructive examination activities that included seven types of examinations. The licensee did not identify any relevant indications accepted for continued service during the nondestructive examinations.

Inspection Scope The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant System Let-down Heat Exchanger, Drawing # 6600

-M1J-3-7, Component ID # 37

-005, Liquid Penetrant Exam # 1

-ISI-PT-11-003 Solvent Soluble Contrasting Dye Penetrant Examination (PT) Reactor Coolant Core Flood Component ID: 1FCB

-1 Piping,

Description:

FW

-11C1, Drawing #

CF-200, Liquid Penentrant Exam

1. 1-BOP-PT-11-012 Solvent Soluble Contrasting Dye Penetrant Examination (PT) Reactor Coolant Core Flood Component ID: 1FCB

-1 Piping,

Description:

FW

-12C1, Drawing #

CF-200, Liquid Penentrant Exam

1. 1-BOP-PT-11-012 Solvent Soluble Contrasting Dye Penetrant Examination (PT) Containment Building Spray System Containment building spray valve and elbow, Drawing # 5

-BS-1, Component ID # BS

-4B, Radiograph Exam # 1

-BOP-RT-11-016 Radiograph Examination (RT) Reactor Coolant System Steam Generator A, E

-24A Lower Head to Lower Ring Head Weld. Drawing # M1D

-295, Component

1. 03-102, Ultrasonic Exam # 1

-ISI-UT-11-012 Ultrasonic Examination (UT) Reactor Coolant System Steam Generator A, E

-24A Lower Head Ring to Lower Tubesheet Weld. Drawing

1. M1D-295, Component # 03

-103, Ultrasonic Ultrasonic Examination (UT)

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Exam # 1-ISI-UT-11-014 High Pressure Injection System Pipe to Elbow Circumference Seam. Drawing # 17

-MU-27 Sheet 1. Component ID # 23

-063, Ultrasonic Exam # 1

-ISI-UT-11-008 Ultrasonic Examination (UT) High Pressure Injection System Pipe to Pipe Circumference Seam. Drawing # 17

-MU-27 Sheet 1. Component ID # 23

-107, Ultrasonic Exam # 1

-ISI-UT-11-009 Ultrasonic Examination (UT) Steam Generator Letdown pipe, Elbow to Pipe Seam. Drawing # 17-MU-1 Sheet 2, Component ID # 24

-009, Ultrasonic Exam # 1

-ISI-UT-11-010 Ultrasonic Examination (UT) Reactor Coolant System Pressurizer Relief Nozzle Between Z-W Axis.

Drawing # M1G

-69, Component ID # 05-15IR, Visual Exam # 1-ISI-VT-11-034 Enhanced Visual Examination (VT

-1) Steam Generator Steam Generator B Upper Head Manhole studs, washers, and nuts, Drawing # M1D

-295 and M1D-251, Component ID # 03

-120, Visual Exam # 1

-ISI-VT-11-069 Visual Examination (VT

-1) Steam Generator Steam Generator B Lower Head Manhole studs, washers, and nuts, Drawing # M1D

-295 and M1D-251, Component ID # 03

-119, Visual Exam # 1

-ISI-VT-11-068 Visual Examination (VT

-1) Reactor Coolant System Steam Generator Upper Primary Inspection Port (Hand Hold)

Access E-24A, WO 244173-01, Drawing # M1D

-295 (EC 2819), Component ID 3 6.4, Visual Exam

1. 1-ISI-VT-11-023 Visual Examination (VT

-2) Reactor Coolant Steam Generator Upper Primary Visual Examination (VT

-2)

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE System Inspection Port (Hand Hold) Access E-24B, WO 244951

-01, Drawing # M1D

-295 (EC 2819), Component ID # 6.7, Visual Exam

1. 1-ISI-VT-11-024 Reactor Coolant System Reactor lower head bottom mounted in

-core instrumentation Alloy 600 bare metal inspection, Drawing # M

-77 and M1B

-231, Visual Exam # 1

-ISI-VT-11-053 Enhanced Visual Examination (VT

-2) Service Water System Spring Can Hanger HCD H3. Drawing # 13

-SW-110, Component # 54

-059, Visual Exam # 1-ISI-VT-11-059 Visual Examination (VT

-3) The inspectors reviewed records for the following nondestructive examinations

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Main Steam System E-24A Steam outlet nozzle to shell weld (@26 degrees), Drawing # M1D

-295m Component # 03

-117, Magnetic Particle Exam # 1

-ISI-MT-11-001 Dry, Color Contrast, Magnetic Particle Examination (MT)

Containment Building Spray System Containment building spray valve and elbow, Drawing # ISO 5

-BS-1 and 5-BS-101, Component ID #

BS-4B, Radiograph Exam # 1

-BOP-RT-11-012 Radiograph Examination (RT) Containment Building Spray System Containment building spray valve and elbow, Drawing # ISO 5

-BS-1 and 5-BS-101, Component ID #

BS-4B, Radiograph Exam # 1

-BOP-RT-11-013 Radiograph Examination (RT) Containment Building Spray System Containment building spray valve and elbow, Drawing # ISO 5

-BS-1 and 5-BS-101, Component ID #

BS-4B, Radiograph Exam # 1-BOP-RT-11-014 Radiograph examination (RT) Reactor Coolant System Reactor lower head bottom mounted in

-core instrumentation Enhanced Visual Examination (VT

-2)

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Alloy 600 bare metal inspection, Drawing # M

-77 and M1B

-231, Visual Exam # 1

-ISI-VT-11-0 53 During the review and observation of each examination, the inspectors verified that activities were performed in accordance with the ASME Code requirements and applicable procedures. The inspectors also verified the qualifications of all nondestructive examination technicians performing the inspections were current.

The inspectors observed two welds and reviewed the documentation on two welds on the reactor coolant system pressure boundary.

The inspectors directly observed a portion of the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Reactor Coolant Drain Tank Component ID: 1FCB

-1 Piping,

Description:

FW

-12C1, Drawing # CF

-200 Tungsten Inert Gas

- GTAW Reactor Building Spray BS-4B - 8 inch,150 pound, tilting disc check valve, Drawing # M

-236. Tungsten Inert Gas

- GTAW The inspectors reviewed records for the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Reactor Coolant Drain Tank Component ID: 1FCB

-1 Piping,

Description:

FW

-11C1, Drawing # CF

-200 Tungsten Inert Gas

- GTAW Reactor Building Spray BS-4B - 8 inch,150 pound, tilting disc check valve. Weld attaching 45

° elbow to downstream pipe, Drawing #

M-236. Tungsten Inert Gas

- GTAW The inspectors verified, by review, that the welding procedure specifications and the welders had been properly qualified in accordance with ASME Code,Section IX, requirements. The inspectors also verified, through observation and record review, that essential variables for the welding process were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.01.

b. No findings were identified.

Findings

.2 Vessel Upper Head Penetration Inspection Activities (71111.08

-02.02)

a. Inspection Scope

The inspectors reviewed the results of the licensee's bare metal visual inspection of the Reactor Vessel Upper Head Penetrations and verified that there was no evidence of boric acid challenging the structural integrity of the reactor head components and attachments.

The inspectors also verified that the required inspection coverage was achieved and limitations were properly recorded.

These actions constitute completion of the requirements for Section 02.02.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)

a. Inspection Scope

The inspectors evaluated the implementation of the licensee's boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspectors reviewed the documentation associated with the licensee's boric acid corrosion control walkdown as specified in Procedure EN-DC-319. The inspectors also reviewed the visual records of the components and equipment. The inspectors verified that the visual inspections emphasized locations where boric acid leaks could cause degradation of safety

-significant components. The inspectors also verified that the engineering evaluations for those components where boric acid was identified gave assurance that the ASME Code wall thickness limits were properly maintained. The inspectors confirmed that the corrective actions performed for evidence of boric acid leaks were consistent with requirements of the ASME Code. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.03.

b. No findings were identified.

Findings

.4 Steam Generator Tube Inspection Activities (71111.08

-02.04) a. Arkansas Nuclear One

- Unit One (ANO1) replacement steam generators (1E

-24 A&B) are Framatome Enhanced Once Through Steam Generators (EOTSG's).

They were constructed in accordance with the 1989 ASME Boiler and Pressure Vessel Code,Section III.

They are vertically mounted once through heat exchangers with a counter

-flow design. They were installed during the Unit 1 Refueling Outage (1R19) in October 2005. The first inservice inspection was 1R20 in March 2007.

During the 1R20 outage, it was identified that locking of the upper tube support plates to the upper shroud in Steam Generator A had occurred.

This resulted in bowing of the tie rods in the first span (Condition Report CR-1-2007-959). A second inspection was performed in 1R21 which included both primary and secondary side inspections.

The amount of tie rod bowing had increased as well as the number of tube support plate wear indications.

However the growth rate of the wear supported skipping one outage.

In the next outage

, 1R22, only the tubes around the tie rods were inspected to assess the extent of the tie rod bowing only

. Inspection Scope The inspection criteria for 1R23 (October 2011) included the following:

100 percent full length bobbin testing of both generators from tube end to tube.

X-probe of tubes full length around all 52 tie rods in both steam generators.

Plus Point/X probe testing of all proximity signals identified from Lower Tube Sheet to 01S, and all bobbin indications.

Visual examination of the tube plugs - (10 tubes in Steam Generator A and 6 tubes in Steam Generator B).

Diagnostic testing of all bobbin I

-codes with the Plus Point/X

-probe.

Comparison of deposits based on X

-probe data (Condition Report CR-ANO-1-2010-922). This was accomplished by testing the previously tested tubes in both Steam Generators

(~ 69 tubes in Steam Generator A and 10 tubes in Steam Generator B).

There were no secondary side visual inspections.

X-probe of all tubes with tube

-to-tube indications (proximity) due to tie rod bowing

. Results There are two damage mechanism s currently associated with the Arkansas Nuclear One, Unit 1 steam generators.

These include mechanical wear at the tube support plates and tie rod bowing which results in tube to tube contact during cold conditions.

These will be addressed separately below:

Tube Support Plate Wear (Indications

) Steam Generator ID Percent Through Wall 1-19 Percent Percent Through Wall 20-39 Percent Percent Through Wall 40-100 Percent SG A 1456 36 0 SG B 1344 68 2 Maximum Depth was 46 Percent Through Wall (previous indication)95/50 Growth = (~ 3 Percent Through Wall per Effective Full Power Year

) Plugging was performed at > 35 Percent to justify an interval equal to three cycles.

All condition monitoring parameters were met and no in

-situ testing was required. Tie Rod Bowing Historically, tie rod bowing was isolated to Steam Generator A only. The bowing is a result of the edges of the tube support plates being frictionally locked to the inner shroud during cool downs.

During operation, the support plates go back to their free movement status and the rods straighten out.

This is evident by no in

-service tube to tube wear.

During the 1R23 inspection, bowing was identified in both steam generators.

The extent of the bowing will be discussed below: Steam Generator A Refuel outage 1R21 was the fourth inspection where bowing ha d been identified.

An operability evaluation was developed that addresses the projected curve of bowing based on the number of thermal cycles the unit experiences.

Currently the unit has experienced six total thermal cycles. The operability was developed based on both laboratory testing of the tie rods and the support plates and various other analytical models. The maximum extent of the bowing is projected to be approximately 2.0 inches of lateral bow in the first span tie rods.

The first span is defined by the area between the top of the lower tube sheet to the first support plate.

This span has the longest vertical distance and the smallest diameter tie rods. Therefore the maximum extent of bowing is exhibited in the first span.

Based on the projected curve, at six thermal cycles, the bowing could be as much as 1.6 inches of vertical bow. The actual results were consistent with the last inspection results of slightly below 1.3 inches. Steam Generator A has been consistent with the previous results and within the projected estimates in the operability.

Two tubes in Steam Generator A, with tie rod bowing in the first span, display what appears to be geometric deformations just above the lower tube sheet, at the mid

-

span (point of maximum bow) and just below the first tube sheet plate. The two tubes are Row 43 Tube 8 and Row 88 Tube 9. These deformations are seen by the various eddy current (ET) techniques (bobbin, array and +Point) as fill factor or lift

-off variations with no evidence of tube wall loss.

The geometric indications in these two tubes are basically the same. There was one indication just above the lower tube sheet (LTS) which responds like a bulge; multiple indications at the mid

-span which respond like a "wrinkled" area and one indication at the lower edge of the first tube sheet plate (01S) which responds like a dent. Both tubes were removed from service.

Steam Generator B This was the first time that bowing ha d been identified in Steam Generator B. The extent of the bowing was approximately 0.5 inch which is well below that of Steam Generator A. There was a delta , in that the direction of the bowing in the first span in Steam Generator A was typically toward the center of the generator.

The bowing in Steam Generator B is multi

-directional.

It is on the "X" side of the generator as compared to Steam Generato r A which is on the "Z" side of the generator.

This is being addressed through the condition report system under CR

-ANO-1-2011-1925. Repair:

The following tubes were repaired during the outage. There were seven in Steam Generator A and nine in Steam Generator B. These actions constitute completion of the requirements of Section 02.04.

b. No findings were identified.

Findings

.5 Identification and Resolution of Problems (71111.08

-02.05) a. The inspectors reviewed 67 condition reports which dealt with inservice inspection activities and found the corrective actions for inservice inspection issues were appropriate. The specific condition reports reviewed are listed in the documents reviewed section. From this review, the inspectors concluded that the licensee has an appropriate threshold for entering inservice inspection issues into the Corrective Action Program and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying industry inservice inspection operating experience. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

These actions constitute completion of the requirements of Section 02.05.

b. No findings were identified.

Findings 1R 11 Licensed Operator Requalification Program (71111.11)a. On November 29, 2011, the inspectors observed a Unit 2 crew of licensed operators in the plant's 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 Crew's clarity and formality of communications

Crew's ability to take timely actions in the conservative direction

Crew's prioritization, interpretation, and verification of annunciator alarms Crew's correct use and implementation of abnormal and emergency procedures Control board manipulations

Oversight and direction from supervisors

Crew's ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications The inspectors compared the crew's performance in these areas to pre

-established 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

R12 Maintenance Effectiveness

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

Inspection Scope November 29, 2011, Alternate AC generator December 15, 2011, Unit 1 L

-1 Turbine building crane December 22, 2011, Unit 2 emergency diesel generators December 30, 2011, Unit 1 reactor building spray 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 four (4) quarterly maintenance effectiveness sample s as defined in Inspection Procedure 71111.12-05. b. No findings were identified.

Findings

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 October 25, 2011, Unit 1, 1R23 outage risk assessment November 11, 2011 Unit 1 and Unit 2, tornado warning with Unit 1 in mode 6 and Unit 2 at 100 percent power 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 two (2) maintenance risk assessments and emergent work control inspection sample s as defined in Inspection Procedure 71111.13-05. b. No findings were identified.

Findings

1R15 Operability Evaluations and Functionality Assessments

a. The inspectors reviewed the following issues:

Inspection Scope June 15, 2011, Unit 1 manhole MH-9 broken fire barrier inside manhole October 15, 2011, Unit 1, unplanned failure of "D" reactor protection system power supply December 7 and 19, 2011, Unit 1, removal of emergency switchgear room chillers, VCH- 4 A and B, from service for planned maintenance December 12, 2011, Unit 1, degraded in

-core detector at IDC

-32 level 1 that resulted in a quadrant power tilt exceeding the limit for operation above 60 percent reactor power 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 SAR to the licensee personnel's 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 four (4) operability evaluations inspection sample(s) as defined in Inspection Procedure 71111.15-05. b. Introduction

. The inspectors identified a Green noncited violation of Unit 1 Technical Specification 3.8.4, "DC Sources

-Operating," Technical Specification 3.8.7, "Inverters

- Operating," and Technical Specification 3.8.9, "Distribution Systems

-Operating," due to the licensee's failure to complete the associated required action prior to the specified completion time while the associated emergency switchgear room chillers were out of service for planned maintenance.

Findings Description

. On December 7, 2011, the licensee entered the following: (1) Technical Specification 3.7.7 Condition A for one loop of service water being inoperable with an associated completion time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; (2) Technical Specification 3.8.1 Condition B for one emergency diesel generator inoperable with a 7 day completion time; and (3) Technical Specification 3.0.6 to support VCH

-4A, Train B emergency switchgear room chiller, being out of service for planned maintenance. The licensee entered those Technical Specifications at 5:35 a.m. on December 7, 2011 and exited the respective technical specifications at 8:51 a.m. on December 8, 2011 after successful completion of surveillance test procedure OP

-1104.027, "Battery and Emergency Switchgear Cooling System," Revision 40 for the VCH

-4A chiller. On December 19, 2011 at 3:19 a.m., the licensee entered the same technical specifications for the other loop of service water listed above to support VCH

-4B, Train A emergency switchgear room chiller, being out of service for planned maintenance. The licensee exited those technical specifications at 6:47 p.m. on December 19, 2011 after successful completion of surveillance test procedure OP

-1104.027 for the VCH

-4B chiller.

The VCH-4 emergency switchgear chillers are non

-technical specification equipment that support safety related equipment with associated technical specificatio n requirements. Specifically, Technical Specification 3.8.4, "DC Sources

- Operating," requires, in part, for one DC electrical power subsystem inoperable in Modes 1, 2, 3, or 4 for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, action must be taken to place Unit 1 in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Technical Specification 3.8.7, "Inverters

- Operating," requires, in part, that for two or more inoperable inverters in one of the two trains, while in Modes 1, 2, 3, or 4

, action must be taken to place Unit 1 in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Technical Specification 3.8.9, "Distribution Systems

- Operating," requires, in part

, that for one AC, DC, or 120 VAC electrical power distribution subsystems inoperable in Modes 1, 2, 3, or 4 for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, action must be taken to place Unit 1 in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Conversely, Technical Specification 3.7.7 for one loop of service water inoperable has a completion time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

The issue was identified to the licensee and entered into the licensee's corrective action program as Condition Report CR-ANO-1-2012-0043.

Analysis.

The inspectors determined that not completing the associated required actions for the appropriate technical specifications prior to the specified completion time while the associated emergency switchgear room chillers were out of service for planned maintenance is a performance deficiency.

The performance deficiency is determined to be more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and affect s the associated cornerstone objective to ensure availability, reliability, and the capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. Specifically, failure to complete the required actions prior to the specified completion times for Technical Specification 3.8.4, "DC Sources

- Operating," Technical Specification 3.8.7, "Inverters

- Operating, and Technical Specification 3.8.9, " Distribution Systems

- Operating," due to removing the respective VCH

-4 from service for maintenance, was a violation of technical specifications. Using Inspection Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," the finding was determined to require a Phase 2 analysis because removing each VCH

-4 chiller from service in December 2011 did result in an actual loss of safety function of a single train for greater than its technical specification allowed completion time. A phase 2 analysis from a previous noncited violation that bounds this issue determined the finding to be of very low safety significance (Green). Specifically, although the function was lost by the designated support equipment (emergency switchgear chillers), the licensee ha d an evaluation that credited compensatory measures and specific environmental conditions that assured the overall functionality of the applicable switchgear train was not lost. The inspectors reviewed the engineering change EC -25691, "Prepare EC markup to CALC-92-E-0103-01 to determine maximum outside ambient temperatures and compensatory measures to allow one chiller train to cool DC/BATT/SWGR areas during maintenance," and determined the overall functionality of the applicable switchgear train was not lost, however, the compensatory measures sufficed for the function, but did not satisfy the technical specification switchgear operability requirements. The finding was determined to have a cross

-cutting aspect in the area of human performance, associated with the decision making component, in that 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 that it is unsafe in order to disapprove the action H.1(b).

Enforcement.

Technical Specifications 3.8.4, "DC Sources

- Operating," requires, in part, both DC electrical power subsystems shall be operable in Modes 1, 2, 3, or 4. Technical Specification 3.8.7, "Inverters

- Operating," requires, in part

, that two red train inverters and two green train inverters shall be operable in Modes 1, 2, 3, or 4. Technical Specification 3.8.9, "Distribution Systems

- Operating," requires, in part

, that two AC, DC, and 120 VAC electrical power distribution subsystems shall be operable in Modes 1, 2, 3, or 4. Technical Specification 3.8.4 and 3.8.9 require that if one DC electrical power subsystem, or one AC electrical distribution, or one DC electrical distribution, or one 120 VAC electrical power distribution subsystem is inoperable for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, action must be taken to place Unit 1 in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Technical Specification 3.8.7 requires that if two or more inverters are inoperable

, Unit 1 must be placed in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

Contrary to the technical specification's required action statements

, on December 7, 2011, the B train DC electrical power subsystem, the B train inverters, and the B train AC, DC, and 120 VAC electrical power distribution subsystems were inoperable due to a lack of emergency switchgear cooling for greater than the allowed completion time and the licensee failed to take the appropriate required actions. In addition, on December 19, 2011, the A train inverters were also inoperable due to a lack of emergency switchgear cooling and the unit was not placed in Mode 3 within the required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Because this violation was of very low safety significance and has been entered into the corrective action program as Condition Report CR-ANO-1-2012-0043, this violation is being treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000313/2011005

-01, "Exceeded Technical Specification Allowed Completion Time for Electrical Power Systems".

1R18 Plant Modifications

.1 a. Temporary Modifications

To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the following temporary modifications:

Inspection Scope November 3, 2011, Unit 1, temporary electrical power for spent fuel pool cooling P-40A November 15, 2011, Unit 2 , reactor coolant system temperature T hot input to core protection calculator C The inspectors reviewed the temporary modification s and the associated safety

-evaluation screening against the system design bases documentation, including the SAR and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed o n the affected equipment, and licensee personnel evaluated the combined effects on mitigating systems and the integrity of radiological barriers.

These activities constitute completion of two (2) sample s for temporary plant modifications as defined in Inspection Procedure 71111.18-05. b. No findings were identified.

Findings

.2 a. Permanent Modifications

The inspectors reviewed key parameters associated with energy needs, materials, replacement components, timing, heat removal, control signals, equipment protection from hazards, operations, flow paths, pressure boundary, ventilation boundary, structural, process medium properties, licensing basis, and failure modes for the permanent modification identified as replacement of valve SW-9, and installation of valve SW-23 to provide boundary isolation from emergency cooling pond to service water. Inspection Scope The inspectors verified that modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure actions, key safety functions, or operator response to loss of key safety functions; post

-modification testing will maintain the plant in a safe configuration during testing by verifying that unintended system interactions will not occur; systems, structures and components' performance characteristics still meet the design basis; the modification design assumptions were appropriate; the modification test acceptance criteria will be met; and licensee personnel identified and implemented appropriate corrective actions associated with permanent plant modifications. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one (1) sample for permanent plant modifications as defined in Inspection Procedure 71111.18-05.

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 October 14, 2011, Unit 2 control element assembly trip circuit breakers November 1, 2011, Unit 1, control valve CV-1405, train A reactor building sump outlet valve following refurbishment 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:

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 SAR , 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 two (2) postmaintenance testing inspection sample s as defined in Inspection Procedure 71111.19-05. b. No findings were identified.

Findings

R20 Refueling and Other Outage Activities

a. The inspectors reviewed the outage safety plan and contingency plans for the Unit 1 1R23 refueling outage, conducted October 16, 2011, through November 2 2, 2011 , to confirm that licensee personnel had appropriately considered risk, industry experience, and previous site

-specific problems in developing and implementing a plan that assured maintenance of defense in depth. During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

Inspection Scope Configuration management, including maintenance of defense in depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.

Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error.

Status and configuration of electrical systems to ensure that technical specifications and outage safety

-plan requirements were met, and controls over switchyard activities.

Monitoring of decay heat removal processes, systems, and components.

Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

Reactor water inventory controls, including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

Controls over activities that could affect reactivity.

Maintenance of secondary containment as required by the technical specifications.

Refueling activities, including fuel handling and sipping to detect fuel assembly leakage.

Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing.

Licensee identification and resolution of problems related to refueling outage activities.

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

These activities constitute completion of one (1) refueling outage and other outage inspection sample as defined in Inspection Procedure 71111.20-05. b. (1) Failure to Implement Procedure Results in Lowering Spent Fuel Pool Level by 0.6 Feet Finding s

Introduction:

The inspectors documented a Green, self

-revealing, noncited violation of Unit 1 Technical Specification 5.4.1.a for the failure to implement station procedure OP-1104.006 "Spent Fuel Pool Cooling System", Revision 51. Specifically, SF

-10, flow control to purification loop valve

, was found 3 turns open when it was required to be closed. This resulted in the spent fuel pool level lowering by 0.6 feet, which is below procedural limits, when the fuel transfer canal was placed in purification and SF

-45, transfer tube isolation valve, was closed to support diving operations in the Unit 1 spent fuel pool tilt pit.

Description:

On November 2, 2011, F

-4A spent fuel filter was replaced and station procedure OP

-1104.006 step 27.2 was performed to fill and vent the filter to place it back into service. During step 27.2.3.A, valve SF-10 was positioned to approximately 25 percent open to support the fill and vent of the filter. Later that day, operations performed step 24.0 of station procedure OP

-1104.006 to place the fuel transfer canal and reactor cavity on purification. Prior to performing this operation, step 27.2.8.A.1 of

OP-1104.006 direct ed the closing of valve SF-10 to prevent spent fuel pool cooling pump discharge water for cooling the pool from entering the spent fuel pool purification loop. Flow control valve SF

-10 was not fully closed prior to placing the fuel transfer canal on purification.

On November 3, 2011, Unit 1 received a spent fuel pool low level alarm which is received when the pool level reaches

-0.5 ft. At that time the fuel transfer canal was on purification in accordance with station procedure OP

-1104.006 and SF

-45 transfer tub e isolation valve was closed to isolate the spent fuel pool tilt pit to support diving operations. Prior to closing SF

-45, spent fuel pool level, as indicated by level indicator LI- 2004, was

-0.3 ft. Operations secured fuel transfer purification and indicated level was -0.9 ft which was below the procedural limit of

-0.5 ft. Operations then opened SF-45 which allowed water to sluice back to the spent fuel pool from the reactor cavity and the spent fuel pool level returned to

-0.3 ft. During investigation of the spent fuel pool low level alarm, operations determined that valve SF-10 was open approximately three turns. This allowed the spent fuel pool cooling pumps to pump water from the spent fuel pool to the suction piping for the decay heat removal pumps. The decay heat removal pumps were operating and pumped the water to the reactor coolant system and into the reactor cavity. When SF

-45 was closed the water could not sluice back into the spent fuel pool from the reactor cavity.

Approximately 4

, 500 gallons of water in the spent fuel pool was transferred to the reactor cavity The licensee identified that a purification valve line up was performed on November 2, 2011 prior to placing the fuel transfer canal on purification during which two operators checked SF

-10 in the closed direction using normal force and verified closure by checking stem position that only showed threads. On November 3, 2011 when operators checked the position of SF

-10 and found it to be open approximately three turns, they had to use excessive force including a torque amplifying device to close the valve. The licensee performed a human performance error review in accordance with station procedure EN

-HU-103 "Human Performance Error Reviews", Rev. 6. The review determined that the condition of the valve not being closed was the result of degraded plant equipment and not the result of a human performance error.

Additional actions taken by the licensee included: (1) documenting that SF

-10 requires a torque amplifying device to operate in CR

-ANO-1-2011-2495 , (2) hanging a caution card on SF-10 stating that a torque amplifying device is required to operate the valve

, and (3) initiating a work request to address the valve condition.

Analysis:

The failure of operations personnel to implement the requirements of procedure OP-1104.006, "Spent Fuel Pool Cooling System," Revision 51, and close valve SF-10 is a performance deficiency

. The performance deficiency is more than minor because it was associated with the configuration control attribute of the Barrier Integrity cornerstone and adversely affect s the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events and is therefore a finding. Using Manual Chapter 0609.04, "Phase 1

- Initial Screening and Characterization of Findings," the finding was determined to have very low safety significance (Green) because the finding did not result in the loss of spent fuel pool cooling, did not result from fuel handling errors that caused damage to the fuel clad integrity or a dropped assembly and did not result in a loss of spent fuel pool inventory of greater than 10 percent of the spent fuel pool volume. The finding was determined to have a cross

-cutting aspect in the area of human performance, associated with the work control component in that the licensee failed to ensure that work activities to support long term equipment reliability limited operator work

-arounds when a torque amplifying device was required to shut valve SF-10 H.3(b).

Enforcement:

Technical Specification 5.4.1.a states, in part, that written procedures shall be implemented in accordance with Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 3.h, of Appendix A, "Procedures for Startup, Operation and Shutdown of Safety

-Related PWR Systems," requires procedures for operating the fuel storage pool purification and cooling system. Station procedure OP

-1104.006, "Spent Fuel Cooling System", Revision 51, step 27.2.8.A.1, state d to close valve SF-10 prior to returning the fuel transfer canal on purification after the completion of filling and venting spent fuel pool purification filter F

-4A. Contrary to the above, valve SF-10 was not closed prior to placing the fuel transfer canal on purification causing spent fuel pool level to decrease below procedural limits. Because this finding is of very low safety significance and has been entered into the corrective action program as Condition Report CR-ANO-1-2011-2498, this violation is being treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000313/2011005

-02, "Failure to Implement Procedure Results in Lowering Spent Fuel Pool Level by 0.6 Feet." (2) Failure to Identify and Correct Unit 1 Service Water Pump Column Protective Wrap Installation Deficiencies.

Introduction

. The inspectors documented a Green, self

-revealing, noncited violation of 10 CFR 50 Appendix B, Criterion XVI, "Corrective Action," for the licensee's failure to promptly identify and correct a condition adverse to quality associated with degradation of the protective wrap (brand name

- Denso) installed on the Unit 1 service water pump columns. The Denso protective wrap around the P

-4C service water pump suction column became unraveled and was drawn into the service water pump suction while running , causing the pump to be secured due to pump discharge strainer high differential pressure.

Description

. On November 15, 2011, during realignment of service water suction from the emergency cooling pond to the lake intake structure, the control room received a P-4C service water pump discharge strainer high differential pressure alarm. The alarm was received immediately after cross connecting the service water bays B and C via sluice gate 4. The discharge strainer differential pressure rose to at least 25 psid (maximum reading on the differential pressure instrument) and operations personnel manually placed the standby P

-4B service water pump in service and secured the P

-4C pump. At the time of the event, service water loop I was operable and being supplied from the P

-4A pump and met the technical specification for service water supply for Unit 1 in Mode 6. Upon investigation, the licensee determined that the Denso protective wrap applied to the P

-4C service water pump column, per Engineering Request, ER-963315E110 in 2005, had become unraveled and was pulled into the pump suction, resulting in debris that clogged the pump discharge strainer. The licensee entered the issue into the corrective action program as Condition Report CR-ANO-1-2011-2843. The licensee took immediate corrective action and removed the Denso protective wrap from all pump columns in the Unit 1 service water intake structure bays. Unit 2 does not have Denso protective wrap installed on their service water pumps.

The licensee performed an apparent cause evaluation that focused on the design change that installed the Denso protective wrap and determined that the design change should have integrated the following items into the design change: (1) the tape product was not specifically designed, qualified, or dedicated for nuclear application; (2) detail ed engineering instructions for installation of the product should have been provided; (3) preventive maintenance requirements to identify degradation over time should have been developed; and (4) an estimate for the lifetime of the product in th is application should have been determined. The apparent cause evaluation also identified that repeated occurrences of degradation since the original installation should have prompted numerous organizations to question the on

-going integrity of the protective wrap applied to the pump columns in the Unit 1 intake structure bays.

The inspectors reviewed the apparent cause evaluation and identified three condition reports since 2005 that identified degradation of the Denso protective wrap applied to the P4-A and P-4C service water pumps. The latest Condition Report, CR-ANO-1-2011-0493 written on April 14, 2011, described two sections of Denso wrap that had peeled off and were hanging from the P

-4C service water pump column. One piece was about 18 inches in length and the other section was split into two pieces of several inches each. The condition report only considered this issue as a long term corrosion concern and determined that it had no immediate impact on the pump operability. No evaluation was performed regarding the impact of additional unraveling of the Denso wrap to the service water pump's operability. The only corrective action performed was to immediately trim the loose pieces of Denso wrap to prevent further unraveling.

Analysis.

The failure to promptly identify and correct a condition adverse to quality associated with degradation of the protective wrap (brand name

- Denso) installed on the Unit 1 service water pump columns is a performance deficiency. The performance deficiency is determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affect s the cornerstone objective to ensure availability, reliability, and the capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. The inspectors performed the significance determination for the failure of service water pump 4C using NRC Inspection Manual Chapter 0609, Attachment 0609.04, "Phase 1

- Initial Screening and Characterization of Findings." The problem had occurred during an outage, but it could have occurred at power during a system realignment. The at

-power model was more conservative, so it was used to evaluate the finding. Service water was a two train system with a swing pump (an installed spare). The allowed outage time for one train was 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Operators could easily align the swing pump to provide the train B service water loads within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Therefore, this finding screened to Green because: 1) it was not a design or qualification deficiency; 2) it did not result in loss of safety function of one train of equipment for more than its technical specification allowed outage time; 3) It did not result in a loss of one train of non

-technical specification equipment; and 4) it did not screen as potentially risk significant due to an external event.

The finding was determined to have a cross

-cutting aspect in the area of problem identification and resolution, associated with the corrective action program component , in that, the licensee failed to thoroughly evaluate problems such that the resolutions address causes and extent of conditions. Specifically, the failure to thoroughly evaluate identified issues with the protective wrap prevented corrective action to be taken to prevent the deficiencies with the service water pump P.1(c).

Enforcement

. Title 10 of the Code or Federal Regulations, Part 50, Appendix B, Criterion XVI states, in part, "Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformance's are promptly identified and corrected." Contrary to the above, from 2005 to November 15, 2011, the licensee failed to ensure that a known condition adverse to quality associated with the degradation of the Denso protective wrap

, on the Unit 1 service water pumps

, was thoroughly evaluated for continued degradation and/or corrected in a timely manner. Because this finding is of very low safety significance and has been entered into the corrective action program as Condition Report CR-ANO-1-2011-2843, this violation is being treated as a noncited violation consistent with Section 2.3.3.a of the NRC Enforcement Policy:

NCV 0500313/2011005

-03, "Failure to Identify and Correct Unit 1 Service Water Pump Column Protective Wrap Installation Deficiencies."

(3) Failure to Identify and Correct a Condition Adverse to Quality Resulted in Dropping a Fuel Bundle Approximately One Inch

Introduction.

The inspectors identified a Green, noncited violation of 10 CFR 50, Appendix B, Criterion XVI for failure to identify and correct a condition adverse to quality. Specifically, on November 1, 2011, the licensee failed to identify and correct a condition associated with seating an irradiated fuel bundle into a reactor building storage location during core re

-loading activities.

The licensee failed to thoroughly evaluate a discrepancy associated with an unexpected vertical measurement when inserting an irradiated fuel bundle into a reactor building storage location. This resulted in the bundle dropping 1 1/8 inches at the storage location.

Description.

On November 1, 2011, the licensee was reloading the Unit 1 reactor core and was experiencing some difficulty inserting an irradiated fuel bundle, NJ0C12, into core location A

-10. At this time the reactor building was open to the atmosphere. The refueling team decided to move the fuel bundle to the reactor building storage rack C, while attempting to adjust fuel bundles surrounding core location A

-10. The ZZ

-tape, (the vertical measuring system used for fuel bundle placement

) indicated that the irradiated fuel bundle was at 32 feet and 1/4 inch. This measurement was 1 5/8 inch higher than the nominal reading for this location. The refueling team raised and set the fuel bundle down again and obtained the same ZZ

-tape measurement. The nominal reading was noted as 31 feet 10 and 5/8 inch in Attachment J, "Main Fuel Bridge (H

-1) Fuel Hoist ZZ Tape Readings and Weight Setpoints," of procedure OP

-1502.003, "Refueling Equipment and Operator Checkouts," Revision 35. The table also stated an allowable tolerance of

+1/2 inch difference between the current ZZ

-tape reading and the nominal readings obtained during fuel handling. System and reactor engineering were notified for resolution.

In an attempt to verify that the fuel bundle was fully seated, the refueling team used a n underwater camera to inspect and evaluate the top portion of the bundle and the storage rack. A visual comparison was performed with a smooth side dummy bundle two storage locations away. The refueling team did not visually identify any height difference. Reactor engineering, without going to the refueling bridge, approved the as found ZZ-tape measurement as the current vertical measurement.

After fuel bundle adjustments were made in the reactor core, the refueling team went to the storage rack to retrieve fuel bundle NJ0C12 to load it into core location A

-10. When the grapple was lowered onto the assembly

, the bundle dropped approximately 1 1/8 inches in the storage rack. An immediate visual inspection did not identify any obvious damage. The licensee decided not to use the bundle. An evaluation later performed by AREVA determined that, although there was no visual damage to the bundle, the fuel pellets may have been damaged due to the 11g of force experienced as a result of the drop. Another bundle was identified for use and a new core design was developed and approved.

The licensee performed a lower tier apparent cause evaluation, which determined that no human performance errors were involved in this event

, and the ir apparent cause for the dropped bundle was an inadequate procedure that failed to give specific guidance to move fuel bundles to the reactor building storage racks and to verify that the fuel bundle is fully seated in the storage rack. The licensee did not address any human performance issues associated with this event.

The inspectors determined that the licensee failed to identify that the fuel bundle was not fully seated in the storage location, and failed to correct that condition prior to un-grappling. The inspectors also determined that the licensee failed to thoroughly evaluate the discrepancy between the vertical fuel bundle measurement and the expected nominal measurement.

The refueling team did attempt to verify fuel bundle position with an underwater camera, but incorrectly compared the heights of the smooth sided dummy bundle, which is shorter in height, and the fuel bundle. The licensee failed to look at the bottom of the storage location for confirmation that the bundle was fully seated. The refueling team did not note any ZZ

-tape vertical measurement discrepancies with any other locations, nor did they review any measurement data to rule out any issue with the ZZ

-tape. The licensee also incorrectly assumed that the reactor building storage racks on Unit 1 (Babcox & Wilcox) were designed the same as the Unit 2 (Combustion Engineering) storage racks. The Unit 1 storage racks have a cruciform on the bottom of the rack to help align and seat the fuel bundle. The licensee did not thoroughly evaluate the fuel bundle measurement, convinced themselves that the ZZ-tape discrepancy was acceptable and decided to accept the discrepancy.

The inspectors determined that the discrepancy associated with the ZZ

-tape should have placed the issue into the corrective action program, but was not placed into the program until the bundle was dropped.

Analysis.

The inspectors determined that the failure to identify and correct the condition associated with the incorrect placement of an irradiated fuel bundle into a reactor building storage location, is a performance deficiency because the licensee failed to place the nuclear fuel in a safe position. The performance deficiency is determined to be more than minor because it is associated with the human performance attribute of the Barrier Integrity cornerstone and adversely affect s the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the performance deficiency resulted in a dropped bundle that caused the bundle to be removed from service due to possible fuel pellet damage. The event also took place during core reloading activities, in which the reactor building was open to the atmosphere. Using Manual Chapter 0609, Appendix G, Attachment 1, Checklist 4, "PWR Refueling Operation: RCS Level >23'," the finding was determined to have very low safety significance (Green) because the finding did not adversely affect:

1) core heat removal, 2) inventory control, 3) electrical power, 4) containment control, or 5) reactivity control. The finding was determined to have a cross

-cutting aspect in the area of human performance, associated with the decision making component in that the licensee failed to use conservative assumptions and adopt a requirement to demonstrate that the proposed action is safe in order to proceed when deciding to accept the discrepancy in the vertical measurement when storing a fuel bundle in the reactor building storage rack H.1(b).

Enforcement

. Title 10 of the Code of Federal Regulation Part 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that "Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non

-conformances are promptly identified and corrected." Contrary to the above, on November 1, 2011, the licensee failed to identify and correct a condition adverse to quality regarding the placement of a fuel bundle in a storage location when confronted with evidence that the fuel bundle may not have been fully seated in that location.

The fuel bundle subsequently dropped 1 1/8 inches. The drop was of sufficient force to render the bundle unusable due to possible fuel pellet damage concerns. Because this finding is of very low safety significance and has been entered into the corrective action program as Condition Report CR-ANO-1-2012-0110, this violation is being treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000313/2011005

-04 , "Failure to Identify and Correct a Condition Adverse to Quality Resulted in Dropping a Fuel Bundle Approximately One Inch

." (4) Failure to Take Adequate Corrective Actions for Known Fuel Transfer System Deficiencies

Introduction.

The inspectors documented a Green, self

-revealing finding for the failure to take adequate corrective actions for known deficiencies associated with the Unit 1 fuel transfer system. Specifically, the licensee failed to investigate and correct issues that have been identified by site and vendor personnel from 1996 through 2010. This led to repeated fuel transfer system failures and significant core offload and reload delays during the 1R23 refueling outage, which placed the plant in an unplanned configuration for an extended period of time.

Description.

During the most recent Unit 1 refueling outage 1R23, fall 2011, numerous problems associated with the fuel transfer system caused an interruption of fuel transfer activities while offloading and reloading the reactor. Beginning on October 23, 2011, while unloading the core, the refueling team began to experience fuel transfer carriage overloads while moving fuel from the reactor building to the spent fuel pool, on every other fuel transfer. Eventually the overloads became more frequent

, occurring on every fuel transfer until the overload condition could not be cleared and caused fuel transfer activities to be stopped. The licensee subsequently identified worn carriage wheels and cable tension issues as contributing to the overload conditions. The issues were temporarily remedied, but cable tension issues remained. On October 27 reactor core offload was completed, but the fuel transfer system continued to experience overload conditions. No corrective actions were taken during the core defuel ed window to address the overload issue.

On November 1, 2011, reactor core reload began. Cable tension was being monitore d

and was increasing and continued with every fuel bundle transfer. At the time

, the licensee did not know why the cable tension was increasing, but later determined that some increase in tension should have been expected and that actions could have been taken to mitigate the issue. On November 2, the fuel transfer carriage unexpectedly stopped approximately three feet inside the reactor building. The licensee had 69 of 177 fuel bundles loaded into the core at this time. The licensee formed a failure modes analysis team to further investigate the issue. It was determined that the fuel transfer carriage wheels on the North side of the carriage were riding up on top of the railing system in the reactor building. The licensee first attempted to realign the rails on the spent fuel pool side to better align the carriage as it transitioned into the reactor building. This action was not effective and the misalignment persisted. A temporary modification was developed and installed that added a wheel extension to the reactor building side of the fuel transfer carriage to prevent the carriage from riding up on top of the rails. On November 13 core reload was completed.

The current fuel transfer system was not original equipment and was installed in 1986. Beginning in 1996, issues associated with the fuel transfer system have been noted. In 2004, 2005, 2007, 2008, and again in 2010 issues with overloads, worn wheels, sheaves, mechanical binding and even a broken retraction cable had been documented in vendor (AREVA) outage reports and in the licensee's corrective action program. Inspections and pre

-outage fuel system checkouts were performed prior to 1R23 outage and did identify some overload conditions, but they were attributed to not having calibrated the load cell. An inspection of the fuel transfer system was performed under water and without moving the fuel transfer carriage. The refueling team further directed unloaded and dry check runs of the fuel transfer system. Nothing was identified from this inspection. The inspectors reviewed the licensee's root cause evaluation. The root cause evaluated why the fuel transfer system experienced overloads and equipment deficiencies that resulted in the loss of 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> of critical path time. Three root causes were identified: 1) original design and configuration issues, 2) organizational issues such as communication, direction of field activities, application of field resources, and decision making that was inadequate during the 1R23 refueling outage, and 3) that previous vendor reports and operating experience items were not acted upon in a timely manner to correct historical problems. The inspectors believe that the main cause for the fuel transfer issues experienced in 1R23 was the failure to correct known deficiencies that have been plaguing the licensee for years. The root cause further evaluated safety culture aspects associated with this issue and concluded that several safety culture aspects were applicable. Among these were decision making, corrective action program for failing to correct the deficiencies, and the failure to act upon operating experience. The inspectors determined that the safety culture aspect of non

-conservative decision making was the most dominate contributor to not correcting known deficiencies. Specifically, the decision making efforts affecting the fuel transfer system did not reflect a safety minded culture as past experience and vendor recommendations were disregarded.

Analysis.

The failure of the licensee to take effective corrective action for known deficiencies related to the Unit 1 fuel transfer system is determined to be a performance deficiency because it was not in accordance with their corrective action program, was within their ability to foresee and correct, and should have been corrected. The performance deficiency is determined to be more than minor because if left uncorrected the performance deficiency could become a more safety significant issue. Specifically, the licensee's failure to correct known deficiencies of the fuel transfer system demonstrated a lack of knowledge of the system design and function which could fail in unexpected and in unpredictable ways which could lead to more safety significant issues. Using Manual Chapter 0609, Appendix G, Attachment 1, Checklist 4, "PWR Refueling Operation: RCS Level >23'," the finding was determined to have very low safety significance (Green) because the finding did not adversely affect: 1) core heat removal, 2) inventory control, 3) electrical power, 4) containment control, or 5) reactivity control. The finding was determined to have a cross

-cutting aspect in the area of human performance, associated with the decision making component in that the licensee failed to use conservative assumptions and adopt a requirement to demonstrate that the proposed action is safe in order to proce e d rather than a requirement to demonstrate that it is unsafe in order to disapprove the action. Specifically, the decision making efforts affecting the fuel transfer system did not reflect a safety minded culture as past experience and vendor recommendations were disregarded H.1(b).

Enforcement.

Although a performance deficiency was identified, there were no violations of NRC requirements identified during the review of this issue because the Unit 1 fuel transfer system is not safety

-related. The licensee entered this issue into the corrective action program as Condition Report CR

-ANO-1-2011-2558. This finding is being documented as: FIN 05000313/2011005

-05, "Failure to Take Adequate Corrective Actions for Known Fuel Transfer System Deficiencies."

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the SAR, 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.

October 5, 2011, Unit 1 VCH

-4A, loop 2 emergency switchgear room chiller temperature switch surveillance test November 9, 2011, Unit 1, make up and purification system check valve and control valve full flow inservice surveillance test November 10, 2011, Unit 1, fill and vent of makeup and purification

, and the high pressure injection system (TI 2515/177 effort)

November 11, 2011, Unit 1, train A engineer ed safeguards actuation system integrated test November 18, 2011, Unit 1, pressurizer sampling system containment isolation valve SV-1818 local leak rate test December 19, 2011

, Unit 2 containment isolation valve 2CV-4823-2 local leak rate test Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of six (6) surveillance testing inspection sample s as defined in Inspection Procedure 71111.22-05. b. No findings were identified.

Findings

Cornerstone:

Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes

a. The inspector performed an in

-office review of Emergency Plan Implementing Procedure OP-1903.010, "Emergency Action Level Classification," Change 44 submitted by letter dated July 26, 2011. This revision changed a reference in Attachment 9, "EAL Equipment Compensating Measures," of this procedure from referencing a table in the Technical Requirements Manual listing seismic instrumentation to referencing Procedures 1203.025 and 2203.008, "Natural Emergencies," for Units 1 and 2 respectively, were the compensating measures are specified for seismic instrumentation.

Inspection Scope This revision was compared to its previous revision, 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, and to the standards in 10 CFR 50.47(b) to determine if the revision 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, this revision is subject to future inspection.

These activities constitute completion of one (1) sample as defined in Inspection Procedure 71114.04-05. b. No findings were identified.

Findings

1EP6 Drill Evaluation

a. The inspectors observed a Unit 1 simulator training evolution for licensed operators on November 22, 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 postevolution critique for the scenario. The focus of the inspectors' activities was to note any weaknesses and deficiencies in the crew's 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

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 performance indicator data submitted by the licensee for the third Quarter 20 11 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 - Emergency ac Power System (MS06)

a. The inspectors sampled licensee submittals for the mitigating systems performance index - emergency ac power system performance indicator for Units 1 and 2 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 licensee's operator narrative logs, mitigating systems performance index derivation reports, issue 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 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 licensee's 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 two (2) mitigating systems performance index

- emergency ac power system sample s as defined in Inspection Procedure 71151-05. b. No findings were identified.

Findings

.3 Mitigating Systems Performance Index

- High Pressure Injection Systems (MS07)a. The inspectors sampled licensee submittals for the mitigating systems performance index - high pressure injection systems performance indicator for Units 1 and 2 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 licensee's 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 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 licensee's 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 two (2) mitigating systems performance index

- high pressure injection system sample s as defined in Inspection Procedure 71151-05. b. No findings were identified.

Findings

4OA2 Problem Identification and

Resolution (71152)

.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 licensee's 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 Inspection Scope 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 licensee's corrective action program because of the inspectors' observations are included in the attached list of documents reviewed.

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 licensee's corrective action program. The inspectors accomplished this through review of the station's 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. The inspectors performed a review of the licensee's 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 licensee's corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensee's trending reports were reviewed for adequacy. These activities constitute completion of one (1) single semi

-annual trend inspection sample as defined in Inspection Procedure 71152-05. b. No findings were identified. The inspectors did identify the following items during the review: 1) configuration control issues, 2) water intrusion issues into the auxiliary building, turbine building, and manholes; and 3) outage performance with regards to the refueling team performance and refueling equipment. These items have been entered into the corrective action program.

Findings and Observations

.4 Selected Issue Follow

-up Inspection a. During a review of items entered in the licensee's corrective action program, the inspectors recognized a corrective action report documenting an incident where an operator found a diesel oil storage tank outlet valve closed that was required to be open to support the functionality of the alternate AC diesel generator. The licensee entered the issue into the corrective action program as Condition Report CR

-ANO-C-2011-2241. The inspectors reviewed the condition report for impact upon the diesel's functionality and the high risk significance associated with potential loss of functionality of the alternate AC diesel generator.

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 documented a Green, self revealing, noncited violation of Unit 1 Technical Specification 5.4.1.a for the failure to implement station procedure OP-1015.0 49 "Configuration Control Program", Revision

1. Specifically, on multiple occasions, station personnel failed to maintain configuration control through the use of

valve line

-ups and station procedures to ensure that plant components were in required positions.

Findings Description

On September 3, 2011, Unit 1 outside auxiliary operator discovered FO

-37, diesel oil storage tank outlet valve, closed when it was required to be open to supply fuel oil to the alternate AC diesel generator 600 gallon day tank. This condition would have prevented automatic makeup to the day tank but the alternate AC diesel would have started and r un when demanded for approximately 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The licensee determined that FO-37 was not correctly positioned open on August 24, 2011, while performing Attachment B of station operating procedure OP-1104.023, "Diesel Oil Transfer Procedure" during the performance of maintenance on the Unit 1, train A emergency diesel generator. The licensee entered the issue into their corrective action program as Condition Report CR-ANO-C-2011-2241. On October 18, 2011

, while collapsing the pressurizer bubble per station procedure OP-1103.011, reactor vessel level indication became erratic and indicated a low level condition. Draining was secured to evaluate the condition.

After securing the drain it was noted that pressurizer level continued to lower and the quench tank volume continued to rise. After investigation it was determined that RBV

-71B, T hot loop B root vent was open when it should have been closed. This caused an unintended reactor coolant system loss of approximately 525 gallons to the quench tank during the pressurizer bubble collapse effort. The licensee determined that RBV

-71B was not closed as required per station procedure OP

-1103.002, Attachment B, "Valve Lineup after completion of Fill and Vent" at the completion of the previous outage. The licensee entered the issue into their corrective action program as condition report CR

-ANO-1-2011-1740 and 1744.

On October 19, 2011

, while performing station procedure OP

-1104.004, Attachment G , "Decay Heat Coolant Purification Using Alternate Purification," station chemistry personnel determined that the reactor coolant system was not getting cleaner based on the results of the demineralizer effluent sample and th is indicated that there was no flow through the demineralizer. Following an investigation

, it was determined that valves CZ-33 and CZ-34B were closed and should have been open and valve CZ

-35B was open and should have been closed as required by station procedure OP

-1104.004. The mispositioned valves allowed the reactor coolant system flow to bypass the demineralizer. The licensee entered the issue into their corrective action program as Condition Report CR-ANO-1-2011-1812.

On October 23, 2011

, the licensee used station procedure OP-1104.002, "Makeup and Purification System Operation", Supplement 8 to perform a full flow check valve test of the makeup system using the A high pressure injection pump. It was determined that the pump curve data obtained was out of the IST limiting range for the pump. An investigation determined that the equalizing valve for PDT

-1210 D , high pressure flow indication

, was open one

-half turn and caused flow indication to read lower. The valve did not have the hand wheel installed and was operated with channel locks. During the subsequent retest the valve was again found three turns open following its operation to flush the lines. The valve was finally replaced with a new one with a hand wheel. The licensee entered the issue into their corrective action program as Condition Report CR-ANO-1-2011-2312. The inspectors reviewed Condition Report CR

-ANO-C-2011-2942, and its associated apparent cause evaluation relating to 12 potential mispositioned components since June 2011. The evaluation concluded that the causes included

(1) a lack of commitment to program implementation

(2) documents not followed correctly involving both programmatic and component control document usage

and (3) guidance was not well defined or understood.

Based upon the multiple examples of failures to satisfy station configuration control procedures the inspectors have determined the failures to be indicative of a programmatic failure to position plant components as required per the configuration control program.

Analysis:

The inspectors determined that the failure of station personnel to maintain configuration control through the use of valve line

-ups and governing station procedures to ensure reactor plant components were in their required positions , is a performance deficien cy. The performance deficiency is more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affect s the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. Using Manual Chapter 0609.04, "Phase 1

- Initial Screening and Characterization of Findings," the finding included an example that was determined to be an actual loss of safety function of a non

-technical specification train of equipment designated as risk

-significant per 10CFR50.65, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

. A phase 3 significance determination analysis was performed by a Region IV senior reactor analyst. The domina nt core damage sequences for Unit 1 were station blackouts with battery depletion and transients with loss of feedwater and feed and bleed capability. The domina nt core damage sequences for Unit 2 were station blackout with loss of emergency feedwater and once

-through-cooling, loss of 4160 volt vital bus 2A4 with loss of feedwater and once

-through-cooling, and station blackout with an 8

-hour battery depletion. Based on both units having the capability to operate a steam driven emergency feedwater pump during the dominate core damage sequences the finding was determined to have very low safety significance (Green). The finding was determined to have a cross

-cutting aspect in the area of human performance, associated with the work practices component to support human performance in that the licensee failed to define and effectively communicate expectations regarding procedural guidance and personnel follow procedures when performing component positioning in accordance with the licensee's program for configuration control H.4(b).

Enforcement

Technical Specification 5.4.1.a states, in part, that written procedures shall be established, implemented and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 1 of Appendix A to Regulatory Guide 1.33, states in part, that safety related activities should be covered by written procedures such as "equipment contro l." Station procedure OP

-1015.049, "Configuration Control Program", Revision 1, step 6.1 state d the control of plant equipment status is established by performing valve/breaker line

-ups and then governed by procedures, work orders, log readings, or protective tagging. Contrary to the above, on multiple occasions, between September 3 and October 23, 2011, the licensee failed to control plant equipment status by inappropriately performing valve/breaker line

-ups and for failing to follow governing procedures. Because this finding is of very low safety significance and has been entered into the corrective action program as Condition Report CR-ANO-1-2011-2942, this violation is being treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000313/2011005

-0 6 , "Failure to Adequately Implement the Configuration Control Program."

.5 In-depth Review of Operator Workarounds

a. The inspectors selected this issue for review to verify that licensee personnel were identifying operator workaround problems at an appropriate threshold and entering them in the corrective action program, and has proposed or implemented appropriate corrective actions. The inspectors reviewed and evaluated the licensee's operator workaround log, for both Units 1 and 2, operator logs and associated condition reports.

The inspectors considered the following, as applicable, during the review of the

licensee's actions: (1)complete and accurate identification of the problem in a timely manner; (2)evaluation and disposition of operability/reportability issues; (3) consideration of extent of condition, generic implications, common cause, and previous occurrences; (4)classification and prioritization of the resolution of the problem; (5) identification of root and contributing causes of the problem; (6)identification of corrective actions; and (7)completion of corrective actions in a timely manner.

Inspection Scope b. No findings were identified.

Findings

4OA3 Follow-up of Events and Notices of Enforcement

Discretion (71153)

.1 (Closed) LER 050003

68/20090 03 Steam Generator Tube Exceeding Technical Specification Plugging Criteria Remained in Service During Previous Cycles as a Result of the Failure to Use Proper Independent Verification On September 8, 2009, Unit 2 was shutdown in M ode 6 for 2R20 outage activities. During the 'B' steam generator inspection it was discovered that a steam generator tube was incorrectly plugged during the previous outage. During the 2R17 spring outage a steam generator tube with an identified flaw was correctly plugged on the cold leg side of the steam generator but not on the hot leg side. An adjacent steam generator tube on the hot leg side was incorrectly plugged instead. The condition resulted in Unit 2 operating at power

, from April 2005 until discovery

, with a steam generator tube characterized with an approximate 43 percent through wall defect which was in violation of the Unit 2 Technical Specification of less than 40 percent through wall required to be in service

. Licensee investigation determined that the error in plugging was caused by a failure to use proper independent verification that the correct tube was plugged. Both steam generator tubes were plugged to remove them from service.

The issue was placed into the corrective action program as Condition Report CR

-ANO-2-2009-2 3 5 7. A licensee identified noncited violation was documented in Inspection Report 050003 68/200900 4 for this issue. This licensee event report is closed.

.2 (Closed) LER 05000368/2009002 Containment Building Penetration Isolation Valves Open During Core Alterations without Application of Administrative Controls Required by Technical Specifications Due to Inadequate Procedural Instructions

On September 7, 2009, with Unit 2 in Mode 6 for refueling, licensed operators discovered that containment penetration isolation valves located on the return line of the containment atmospheric monitoring system were configured such that a direct path existed between the containment atmosphere and the auxiliary building atmosphere and the resulting containment breech was not being administratively controlled as required by Unit 2 technical specifications. The licensee determined that the system was initially placed in the correct configuration during reactor shutdown, but a local leak rate testing evolution required these vales to be repositioned. The valves were not restored to the required configuration following completion of the local leak rate testing. Core alteration commenced shortly after completion of the testing. The licensee determined that the local leak rate procedure failed to give adequate guidance to restore the system for shutdown plant conditions. The licensee took corrective action to modify the procedure to specify position of the valves depending on the plant mode. The issue was placed into the corrective action program as Condition Report CR

-ANO-2-2009-2329. A licensee identified noncited violation was documented in Inspection Report 05000368/2009004. This licensee event report is closed.

.3 (Closed) LER 05000368/2009004

Emergency Diesel Automatic Actuation While Performing Offsite Power Transfer Testing Due to a High Resistance Contact Supplying Voltage to a Synchronizing Check Relay On September 20, 2009, Unit 2 was shutdown in Mode 5 for 2R20 outage activities. During the performance of planned surveillance testing of the Offsite Power Transfer Test, the 2K

-4A emergency diesel generator automatically started. An Offsite Power Transfer Test was being performed to test automatic transfer from the Startup 3 Offsite Transformer to the Startup 2 Offsite Transformer. During the Offsite Power Transfer Test, a permissive contact in the Startup 2 feeder breaker failed resulting in a slow transfer to the 2A1 bus instead of the expected fast transfer. The slow transfer resulted in a momentary loss of power to the 4160 Volt Safety Electrical Bus 2A3 which is powered from 2A1. The momentary undervoltage condition on 2A3 caused the 2K

-4A emergency diesel generator to auto start as designed. The 2K

-4A emergency diesel generator did not power 2A3, since 2A3 was successfully powered from 2A1 after the slow transfer completed. During the momentary lo ss of power, 2A3 automatically shed all loads as designed. This load shed caused the running shutdown cooling pump, 2P-60A , to secure which resulted in a loss of shutdown cooling flow to the reactor coolant system for approximately three and one half minutes. The licensee determined that the cause of the event was a loss of one of the voltage inputs that feed the 2A1 bus synchronizing check relay (125-111), located in the 2A

-111 breaker cubicle

, due to a high resistance contact. This high resistance condition blocked one of the voltage inputs to the synchronizing check relay, causing the relay to falsely indicate that the startup 2 transformer and the 2A1 bus were not synchronized. The licensee took immediate corrective action to modify the circuit with alternate contacts with the appropriate resistance. The licensee also took corrective action to modify the maintenance procedures for these type breakers to inspect and maintain these contacts. The issue was placed into the corrective action program as Condition Reports CR-ANO-2-2009-2997. A self

-revealing noncited violation was documented in Inspection Report 05000368/2009005 for this issue. The review of this licensee event report is complete and no findings were identified and no violations of NRC requirements occurred. This licensee event report is closed.

4OA5 Other Activities

(Open) NRC TI 2515/177, "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008

-01)" As documented in Section 1R22, the inspectors confirmed the acceptability of the licensee's procedures and processes for filling and venting ECCS systems. This inspection effort counts towards the completion of TI 2515/177 which will be clos ed in a later NRC Inspection Report following further inspection activities to follow

-up on previously identified issues documented in inspection report ANO 2011

-04.

4OA6 Meetings Exit Meeting Summary

On October 28, 2011, the inspectors presented the inspection results of the review of inservice inspection activities to Mr. C. Schwarz, Site Vice President, and other members of the licensee staff. 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 December 1, 2011, the inspector, during a telephonic meeting, discussed the results of the in-office inspection of changes to the licensee's emergency plan and emergency action levels to Mr. R. Holeyfield, Manager, Emergency Preparedness, and other members of the licensee's staff. 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 20, 201 2 , the inspectors presented the inspection results to Mr. M. Chisum, General Manager , Plant Operations, and other members of the licensee staff. 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 violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy for being dispositioned as noncited violations.

Unit 1 Technical Specification 5.4.1.a, requires, in part, that "Written procedures shall be established, implemented, and maintained covering the following activities-the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978." Regulatory Guide 1.33, Revision 2, Appendix A, Section 2 specifies written procedures for the safety

-related activity of refueling and core alterations. Contrary to the above, the licensee failed to implement procedures for core alterations during 1R23 Unit 1 refueling outage. Specifically, on two occasions, the refueling team failed to follow refueling procedures for verifying neutron counts prior to un

-grappling a fuel bundle in the core and for moving a fuel bundle in fast speed prior to obtaining adequate clearance from other fuel bundles in the core. Using Manual Chapter 0609, Appendix G, Attachment 1, Checklist 4, "PWR Refueling Operation: RCS Level >23'," the finding was determined to have very low safety significance (Green) because the finding did not adversely affect: 1) core heat removal

2) inventory control

3) electrical power; 4) containment control

or 5) reactivity control.

These issues were entered into the corrective action program as Condition Reports CR

-ANO-1-2011-2085, and 2552.

Unit 1 Technical Specification 5.4.1.a, requires, in part, that "Written procedures shall be established, implemented, and maintained covering the following activities-the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978." Regulatory Guide 1.33, Revision 2, Appendix A, Section 2 specifies written procedures for the safety

-related activity of refueling and core alterations. Contrary to the above, the licensee failed to provide adequate procedures for refueling and core alterations during 1R23 Unit 1 refueling outage. Specifically, the licensee over rotated a control rod drive lead screw during reactor disassembly and resulted in having to replace the control rod drive mechanism. Using Manual Chapter 0609, Appendix G, Attachment 1, Checklist 4, "PWR Refueling Operation: RCS Level >23'," the finding was determined to have very low safety significance (Green) because the finding did not adversely affect: 1) core heat removal, 2) inventory control, 3) electrical power, 4) containment control, or 5) reactivity control. This issue was entered into the corrective action program as Condition Report CR

-ANO-1-2011-1921.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Schwarz, Site Vice President

D. Bice, Licensing Specialist

B. Byford, Manager, Training

T. Chernivec, Manager, Outages

M. Chisum, General Manager, Plant Operations

B. Daiber, Manager, Design Engineering

A. Dodds, Manager, Maintenance

M. Farmer, Maintenance, Refueling Program Manager

R. Fowler, Senior Emergency Preparedness Planner

R. Fuller, Manager, Quality Assurance

W. Greeson, Manager, Engineering Programs and Component

R. Holeyfield, Manager, Emergency Preparedness

R. Holman, Welding Engineer, Entergy Code Programs

D. Hughes, Manager

(Acting), Engineering Programs and Component

K. Jones, Manager, Operations

B. Lovin, Manager, Security

D. Marvel, Manager, Radiation Protection

J. McCoy, Director, Engineerin

g

R. McGaha, NDE Technician, Entergy Code Programs

D. Metheany, Steam Generator Programs Owner

N. Mosher, Licensing Specialist

B. Pace, Manager, Planning, Scheduling, and Outage

K. Panther, Manager, ISI Program

D. Perkins, Manager, Maintenance

S. Pyle, Manager, Licensing

T. Sherrill, Manager, Chemistry

P. Williams, Manager, System Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000313/2011005

-0 1 NCV Exceeded Technical Specification Allowed Completion

Time for Electrical Power Systems

(Section 1R15)

05000313/2011005

-02 NCV Failure to Implement Procedure Results in Lowering Spent Fuel Pool Level by 0.6 Feet

(Section 1R20(1))

05000313/2011005

-03 NCV Failure to Identify and Correct Unit 1 Service Water Pump Column Protective Wrap Installation Deficiencies

(Section 1R20(2))

05000313/2011005

-04 NCV Failure to Identify and Correct a Condition Adverse to Quality

Attachment

Opened and Closed

Resulted in Dropping a Fuel Bundle Approximately One Inch

(Section 1R20(3))

05000313/2011005

-05 FIN Failure to Take Adequate Corrective Actions for Known Fuel Transfer System Deficiencies

(Section 1R20(4))

05000313/2011005

-0 6 NCV Failure to Adequately Implement the Configuration Control Program (Section 4OA2.4)

Closed

05000368/2009003

LER Steam Generator Tube Exceeding Technical Specification Plugging Criteria Remained in Service During Previous Cycles as a Result of the Failure to Use Proper Independent Verification

05000368/2009002

LER Containment Building Penetration Isolation Valves Open During Core Alterations without Application of Administrative Controls Required by Technical Specifications Due to Inadequate

Procedural Instructions

05000368/200900

LER Emergency Diesel Automatic Actuation While Performing Offsite Power Transfer Testing Due to a High Resistance Contact Supplying Voltage to a Synchronizing Check Relay

Attachment

LIST OF DOCUMENTS REVIEWED

Section 1R

01:

Adverse Weather Protection

PROCEDURES

NUMBER TITLE REVISION

OP-1104.039 Plant Heating and Cold Weather Operations

OP-2106.032 Unit 2 Two Freeze Protection Guide Section 1R

04:

Equipment Alignment

PROCEDURES

NUMBER TITLE REVISION

OP-1104.029 Unit 1 Service and Auxiliary Cooling Water System

OP-1104.036 Unit 1 Emergency Diesel Generator Operation

OP-2104.037 Alternate AC Diesel Generator

OP-1104.032 Unit 1 Fire Protection Systems

OP-2104.032 Unit 2 Fire Protection Systems Operations

DRAWINGS NUMBER TITLE REVISION

M-210 Service Water

150

M-217 Emergency Diesel Generator and Fuel Oil System

M-2241 Alternate AC Generator System

M-2219 Sheet 1 Fire Water System Pipe and Instrument Diagram

M-2219 Sheet 2 Fire Water System Pipe and Instrument Diagram

M-2219 Sheet 4 Deluge Valve Detail

M-2219 Sheet 5 Outside Fire Loop

M-2219 Sheet 7 Deluge Valve Detail

Attachment

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

STM-1-42 Unit 1 Service and Auxiliary Cooling Water

STM-1-31 Unit 1 Emergency Diesel Generators

STM-2-33 Unit 2 Alternate AC Diesel Generator Section 1R

05:

Fire Protection

PROCEDURES

NUMBER TITLE REVISION

FHA ANO Fire Hazard Analysis

PFP-U1 ANO Pre-Fire Plan Unit 1

PFP-U2 ANO Pre-Fire Plan Unit 2

DRAWINGS NUMBER TITLE REVISION

FZ-1063 Unit 1 Fire Zone Detail

- Reactor Building

FZ-1064 Unit 1 Fire Zone Detail

- Reactor Building

FZ-1065 Unit 1 Fire Zone Detail

- Reactor Building

FZ-1066 Unit 1 Fire Zone Detail

- Reactor Building

FZ-1067

Unit 1 Fire Zone Detail

- Reactor Building

FZ-2044 Unit 2 Fire Zone Detail

- Electrical Switchgear, Feedwater Heaters, and Turbine areas

FZ-2025 Unit 2 Fire Zone Detail

- Electrical Equipment (motor generator sets) room

FZ-1030 Unit 1 Service Water Intake Structure Section 1R

06:

Flood Protection Measures

PROCEDURES

NUMBER TITLE REVISION

ULD-0-TOP-17 ANO Topical Flooding

Attachment

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

CALC-92-R-0024-01 Flooding Evaluation INPO SOER

-85-5 0

CALC-92-R-0034-01 Flooding Evaluation INPO SOER

-85-5 2 nd Iteration

ULD-1-SYS-01 ANO Unit 1 Emergency Diesel Generator

ULD-0-TOP-02 Fire Protection Topical

CONDITION REPORTS

CR-ANO-1-2011-1343

CR-ANO-C-2011-0802

CR-ANO-1-2011-0744

CR-ANO-1-2011-0662

CR-ANO-1-2001-0661

CR-ANO-1-2011-0641

Section 1R

07:

Heat Sink Performance

PROCEDURES

NUMBER TITLE REVISION

OP-1309.016 Decay Heat Thermal Test

004-01-0

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

ER-91-R-2013-01 Service Water Performance Testing Methodology

CONDITION REPORTS

CR-ANO-1-2011-2134

CR-ANO-1-2011-2014

CR-ANO-1-2011-1750

CR-ANO-1-2011-1712

Section 1R

8:

Inservice Inspection Activities

DOCUMENTS NUMBER TITLE REVISION / DATE

Entergy Steam Generator Degradation Assessment: Plant and Unit - Arkansas Nuclear One Unit One, Refueling Outage: 1R23 0

Snapshot Assessment / Benchmark On:

Pre-NRC Inspection

- In-service Inspection (ISI)

1R23 August 31, 2011

Quarterly Health Reports 4Q2010, 1Q2011, 2Q2011, 3Q2011

Attachment Section 1R

8:

Inservice Inspection Activities

DOCUMENTS NUMBER TITLE REVISION / DATE

1R20 Cycle Report Spring 2007

1032.037 Inspection And Identification Of Boric Acid Leaks For A

NO-1 a nd A

NO-2 5 1103.013 RCS Leak Detection

1CAN060902

Request for Alternative

- Implementation of a Risk

-Informed

Inservice Inspection Program Based on ASME Code Case N

-716 , Arkansas Nuclear One, Unit 1 , Docket No. 50

-313 License No.

DPR-51 June 11, 2009 1CNA030901

Arkansas Nuclear One, Unit 1, Grand Gulf Nuclear Station, River B end Station, and Waterford Steam Electric Station, Unit 3 - Request for Alternative

CEP-ISI-012, Use Alternative Requirements In ASME Code Case N

-753 (TAC NOS. MD8813, MD8814,

MD8815 AND MD8816)

March 6, 2009

1CNA061001

Arkansas Nuclear One, Unit No. 1

-Request For Alternative A N 01-I

SI-014 Re:

Implementation Of

a Risk-Informed

Inservi ce Inspection Program Based

o n ASME Code

Case N-716 (T AC No. M E 1488) June 2, 2010

20004-017 ENGINEERING INFORMATION RECORD , Document No.: 51

-

9135783 - 000 ,

Technical Summary of Steam Generator Eddy Current Examinations at Arkansas Nuclear One, 1R22

March 2010

51-9135783-000 Areva NP Inc, Engineering Information Record, Technical Summary of Steam Generator Eddy Current Examinations at Arkansas Nuclear One, 1R22.

March 2010

CNRO-2008-00016 Relief Requests for Third 120 Month Inservice Testing Interval May 20, 2008

EN-DC-319 Inspection and evaluation of Boric Acid Leaks

EN-DC-319 Inspection and evaluation of Boric Acid Leaks

LO-ALO-2008-00090 Boric Acid Corrosion Control Program (BACCP) Self Assessment August 13, 2009

LO-ALO-2010-00056 Assessment Report:

Welding Program Assessment August 2011

Attachment

NDE PROCEDURES

NUMBER TITLE REVISION

CEP-NDE-0255 Radiographic Examination ASME, ANSI,AWS Welds and Components

CEP-NDE-0400 Ultrasonic Examination

CEP-NDE-0404 Manual Ultrasonic Examination of Ferritic Piping Welds (ASME XI) 5

CEP-NDE-0407 Straight Beam Ultrasonic Examinations of Bolts and Studs (ASME XI) 3

CEP-NDE-0423 Manual Ultrasonic Examination of Austenitic Piping Welds (ASME XI) 5

CEP-NDE-0497 Manual Ultrasonic Examination of Welds in Vessels (Non

-App. VIII)

CEP-NDE-0641 Liquid Penetrant Examination (PT) for ASME Section XI

CEP-NDE-0731 Magnetic Particle Examination (MT) for ASME Section XI

CEP-NDE-0901

VT-1 Examination

CEP-NDE-0902

VT-2 Examination

CEP-NDE-0903

VT-3 Examination

CONDITION REPORTS

CR-ANO-1-2011-02807

CR-ANO-1-2011-02789

CR-ANO-1-2011-00554

CR-ANO-1-2010-00956

CR-ANO-1-2010-00968

CR-ANO-1-2010-01986

CR-ANO-1-2011-00685

CR-ANO-1-2010-01983

CR-ANO-1-2010-00977

CR-ANO-1-2010-02009

CR-ANO-1-2011-00753

CR-ANO-1-2011-00512

CR-ANO-1-2010-01118

CR-ANO-1-2010-02021

CR-ANO-1-2011-00872

CR-ANO-1-2010-01966

CR-ANO-1-2010-01124

CR-ANO-1-2010-02055

CR-ANO-1-2011-00909

CR-ANO-1-2011-00318

CR-ANO-1-2010-01295

CR-ANO-1-2010-02071

CR-ANO-1-2011-01126

CR-ANO-1-2010-01948

CR-ANO-1-2010-01361

CR-ANO-1-2010-02073

CR-ANO-1-2011-01379

CR-ANO-1-2011-02736

CR-ANO-1-2010-01462

CR-ANO-1-2010-02089

CR-ANO-1-2011-01380

CR-ANO-1-2011-00250

CR-ANO-1-2010-01475

CR-ANO-1-2010-02087

CR-ANO-1-2011-01395

CR-ANO-1-2010-01933

CR-ANO-1-2010-01493

CR-ANO-1-2010-02173

CR-ANO-1-2011-01489

CR-ANO-1-2011-02258

CR-ANO-1-2010-01564

CR-ANO-1-2010-02197

CR-ANO-1-2011-01728

CR-ANO-1-2011-00157

CR-ANO-1-2010-01587

CR-ANO-1-2011-02213

CR-ANO-1-2011-01824

CR-ANO-1-2010-01930

CR-ANO-1-2010-01613

CR-ANO-1-2010-02218

CR-ANO-1-2011-01895

CR-ANO-1-2011-02224

CR-ANO-1-2010-01644

CR-ANO-1-2010-02516

CR-ANO-1-2011-01926

CR-ANO-1-2011-00034

CR-ANO-1-2010-01716

CR-ANO-1-2010-02605

CR-ANO-1-2011-01979

CR-ANO-1-2010-01922

CR-ANO-1-2010-01754

CR-ANO-1-2010-02734

CR-ANO-1-2011-01998

CR-ANO-1-2011-02213

CR-ANO-1-2010-01802

CR-ANO-1-2010-02736

CR-ANO-1-2011-02071

CR-ANO-1-2010-03760

CR-ANO-1-2010-01810

CR-ANO-1-2010-02900

CR-ANO-1-2011-02084

CR-ANO-1-2010-01907

CR-ANO-1-2010-01823

CR-ANO-1-2010-03617

CR-ANO-1-2011-02128

CR-ANO-1-2011-02173

Attachment

CONDITION REPORTS

CR-ANO-1-2010-01856 CR-ANO-1-2010-03754

Section 1R12: Maintenance Effectiveness

PROCEDURES

NUMBER TITLE REVISION

EN-DC-203 Maintenance Rule Program

EN-DC-204 Maintenance Rule Scope and Basis 2

EN-DC-205 Maintenance Rule Monitoring

EN-DC-206 Maintenance Rule (a)(1) Process

ULD-0-TOP-19 Upper Level Document Station Blackout

OP-2104.037 Alternate AC Diesel Generator Operations

MISCELLANEOUS DOCUMENTS

NUMBER TITLE DATE

Maintenance Rule Database Scoping and Performance Criteria

- Unit 1 Alternate AC diesel generator October 12, 2011

Unit 1 Alternate AC diesel generator Functional Failure Determination Report October 12, 2011

Maintenance Rule Database Scoping and Performance Criteria

- Unit 1 Turbine Building November 15, 2011

Unit 1 Turbine Building Functional Failure Determination Report November 15, 2011

Unit 1 Reactor Building Spray

- Maintenance Rule Database Scoping and Performance Criteria November 28, 2011

Unit 1 Reactor Building Spray

- Maintenance Rule Functional Failure Determination Report November 28, 2011

CONDITION REPORTS

CR-ANO-C-201

1-1639

CR-ANO-C-201

1-1971

CR-ANO-C-2011-1862

CR-ANO-1-2011-0567

CR-ANO-C-201

1-0061

CR-ANO-1-2011-1617

CR-ANO-1-2011-2075

CR-ANO-1-2011-0588

CR-ANO-1-2011-0999

Attachment

Section 1R13: Maintenance Risk Assessment and Emergent Work Controls

PROCEDURE NUMBER TITLE REVISION

OP-1203.025 Natural Emergencies

CONDITION REPORTS

CR-ANO-C-2011-2952

Section 1R15: Operability Evaluations

PROCEDURES

NUMBER TITLE REVISION

EN-OP-104 Operability Evaluations

OP-1105.001 Unit 1 Nuclear Instrumentation and Reactor Protection System Operating Procedure

CALCULATIONS

NUMBER TITLE REVISION

CALC-ANO1-NE-11-00002 ANO Unit 1 Cycle 24 Core Operating Limits Report

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

STM-1-63 Unit 1 Reactor Protection System

CONDITION REPORTS

CR-ANO-1-201

1-1655

CR-ANO-1-201

1-1659

CR-ANO-1-2011-1667

CR-ANO-1-2010-3653

CR-ANO-1-201

1-1672

CR-ANO-1-2011-3044

CR-ANO-1-2011-3183

CR-ANO-1-2011-0896

Attachment

Section 1R18: Plant Modifications

PROCEDURES

NUMBER TITLE REVISION

EN-DC-115 Engineering Change Process

EN-DC-136 Temporary Modifications

ENGINEERING CHANGE DOCUMENTS

EC-31408

EC-30016

WORK ORDERS

277055 00279037

Section 1R19: Postmaintenance Testing

PROCEDURES

NUMBER TITLE REVISION

OP-2304.039 Unit 2 Plant Protection System Channel C Test

OP-1305.007 RB Isolation and Miscellaneous Valve Stroke Test

EN-MA-101 Fundamentals of Maintenance

EN-WM-102 Work Implementation and Closeout

EN-WM-105 Planning 9

EN-WM-107 Post Maintenance Testing

WORK O RDER S

50271508 52326209

Section 1R20: Refueling and Other Outage Activities

PROCEDURES

NUMBER TITLE REVISION / DATE 1-OPG-002 Unit 1 Tank Volume Book April 5, 2011

OP-1104.006 Unit 1 Spent Fuel Cooling System

OP-1506.001 Fuel and Control Component Handling

OP-1502.004 Control of Unit 1 Refueling

Attachment

Section 1R20: Refueling and Other Outage Activities

PROCEDURES

NUMBER TITLE REVISION / DATE

OP-1502.003 Refueling Equipment and Operator Checkouts

OP-1103.011 Draining and N

Blanketing the RCS

EN-OM-123 Fatigue Management Program

CONDITION REPORTS

CR-ANO-1-2011-2495

CR-ANO-1-2011-2498

CR-ANO-1-2011-2843

CR-ANO-C-2011-3017

CR-ANO-1-2011-0493

CR-ANO-1-2005-1405

CR-ANO-1-2010-0370

CR-ANO-1-2011-2558

CR-ANO-1-2011-2211

CR-ANO-1-2011-2814

CR-ANO-1-2011-2815

CR-ANO-1-2010-1028

CR-ANO-1-2011-2412

CR-ANO-1-2011-0769

CR-ANO-1-2011-1846

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

STM-1-51-1 Refueling Machine & Reactor Bldg Fuel Handling Equipment

STM-1-51-2 Spent Fuel Handling & SFP Area Equipment

STM-1-51-3 Fuel Transfer System

Section 1R22: Surveillance Testing

PROCEDURES

NUMBER TITLE REVISION

OP-1305.018 Unit 1 Local Leak Rate Testing

- Type C 23

OP-1305.006 Unit 1 Integrated Engineered Safeguards System Test

OP-1104.002 Unit 1 Makeup and Purification System Operation

OP-1104.027 Unit 1 Battery and Switchgear Emergency Cooling System

OP-2305.017 Local Leak Rate Testing

CONDITION REPORTS

CR-ANO-1-2011-1882

CR-ANO-1-2011-2660

CR-ANO-1-2011-2783

CR-ANO-2-2011-0820

CR-ANO-1-2011-2757

CR-ANO-1-2011-2021

CR-ANO-1-2011-2526

CR-ANO-2-2011-0800

CR-ANO-1-2011-2312

CR-ANO-1-2011-2316

CR-ANO-1-2011-2524

CR-ANO-1-20 11-2700

CR-ANO-1-2011-2516

CR-ANO-1-2011-2130

Attachment

WORK ORDER S

52274060

Section 1EP4: Emergency Action Level and Emergency Plan Changes

PROCEDURES

NUMBER TITLE REVISION

OP-1903.011P SAE Emergency Direction and Control Checklist Shift Manager

OP-1903.011Y Emergency Class Initial Notification Message

Section 4OA1: Performance Indicator Verification

PROCEDURES

NUMBER TITLE REVISION

EN-LI-114 Performance Indicator Process

MISCELLANEOUS DOCUMENTS

NUMBER TITLE DATE

Unit 1 MSPI Derivation Report

- Emergency AC Power System - Unavailability Index October 28, 2011

Unit 1 MSPI Derivation Report

- Emergency AC Power System - Unreliability Index October 28, 2011

Unit 1 Emergency Diesel Generator 1 Conditional Probability Data October 28, 2011

Unit 1 Emergency Diesel Generator 2 Conditional Probability Data October 28, 2011

Unit 1 MSPI Derivation Report

- High Pressure Injection System - Unavailability Index October 28, 2011

Unit 1 MSPI Derivation Report

- High Pressure Injection System - Unreliability Index October 28, 2011

Unit 1 Makeup and Purification 1P36A Pump Conditional Probability Data November 30, 2011

Unit 1 Makeup and Purification 1P36B Pump Conditional Probability Data November 30, 2011

Unit 1 Makeup and Purification 1P36C Pump Conditional Probability Data November 30, 2011

Attachment

Section 4OA2: Identification and Resolution of Problems

PROCEDURES

NUMBER TITLE REVISION

COPD-001 Operations Expectations and Standards

COPD-020 ANO Operations Concerns Program

EN-FAP-OP-006 Operator Aggregate Impact Index Performance Indicator

OP-2304.258 Unit 2 Escape Airlock Leak Rate Test

OP-2305.017 Local Leak Rate Testing

OP-2411.029 Emergency Air Lock Inspection, Lubrication and Chalk Test

OP-1015.001 Conduct of Operations

OP-1015.049 Configuration Control Program

OP-1103.002 Draining and Nitrogen Blanketing the Reactor Coolant System 41

OP-1103.011 Filling and Venting the Reactor Coolant System

OP-1104.004 Decay Heat Removal Operating Procedure

OP-1104.002 Unit 1 Makeup and Purification System Operation

DRAWINGS NUMBER TITLE REVISION

DWG 30970 Emergency Access Airlock

- General Arrangement

DWG 30970 Emergency Access Airlock

- General Assembly

MISCELLANEOUS DOCUMENTS

NUMBER TITLE DATE

Nuclear Oversight Fleet Trimester Report October 2011

Unit 1 Top Ten Reliability Issues Unit 2 Top Ten Reliability Issues

CONDITION REPORTS

CR-ANO-2-2011-0888

CR-ANO-2-2011-1197

CR-ANO-2-2011-1687

CR-ANO-2-2011-3264

CR-ANO-2-2011-0768

CR-ANO-C-2011-2241

CR-ANO-C-2011-2942

CR-ANO-2-2011-3170

CR-ANO-1-2011-1740

CR-ANO-1-2011-1744

CR-ANO-1-2011-1851

CR-ANO-2-2011-3294

Attachment

CONDITION REPORTS

CR-ANO-1-2011-1812

CR-ANO-1-2011-2312

CR-ANO-1-2011-2498

CR-ANO-2-2011-2696

CR-ANO-1-2007-1667

CR-ANO-1-2011-0328

CR-ANO-1-2010-2370

CR-ANO-2-2011-3533

CR-ANO-1-2009-0014

CR-ANO-1-2011-0967

CR-ANO-1-2011-1666

CR-ANO-2-2011-2263

CR-ANO-1-2011-1797

CR-ANO-1-2011-2145

CR-ANO-1-2011-2319

CR-ANO-2-2011-2166

CR-ANO-1-2011-3049

CR-ANO-1-2011-3077

CR-ANO-1-2011-0858

CR-ANO-2-2011-2179

CR-ANO-1-2011-3070

CR-ANO-2-20 08-2360

CR-ANO-2-20 09-0176

CR-ANO-2-2011-1663

CR-ANO-2-2011-3250

CR-ANO-2-20 09-3566

CR-ANO-2-201 0-0923

CR-ANO-2-2011-1687

CR-ANO-2-201 0-0056

CR-ANO-2-2011-0103

CR-ANO-2-2011-0644

CR-ANO-2-2011-1343

CR-ANO-2-2011-0924

CR-ANO-2-2011-1318 CR-ANO-2-2011-1411