ML120450828

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IR 05000313-11-005, 05000368-11-005, on October 1 Through December 31, 2011, Arkansas Nuclear One
ML120450828
Person / Time
Site: Arkansas Nuclear  Entergy icon.png
Issue date: 02/14/2012
From: Allen D
NRC/RGN-IV/DRP/RPB-E
To: Schwarz C
Entergy Operations
References
IR-11-005
Download: ML120450828 (67)


See also: IR 05000313/2011005

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION I V

1600 EAST LAMAR BLVD

ARLINGTON, TEXAS 76011-4511

February 14, 2012

Christopher J. Schwarz, Site Vice President

Arkansas Nuclear One

Entergy Operations, Inc.

1448 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 2. 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 staff.

The inspections examined activities conducted under your license as they relate to safety and

compliance with the Commissions rules and regulations and with the conditions of your license.

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

personnel.

Two NRC identified and four self-revealing findings of very low safety significance (Green) were

identified during this inspection.

Five of these findings were determined to involve violations of NRC requirements. Further, two

licensee-identified violations which were determined to be of very low safety significance are

listed in this report. The NRC is treating these violations as noncited violations (NCVs)

consistent with Section 2.3.2 of the Enforcement Policy.

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 One.

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 One.

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

C. Schwarz -2-

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: 05000313, 05000368

License Nos: DPR-51, NPF-6

Enclosure: Inspection Report 05000313/2011005 and 05000368/2011005

w/ Attachment: Supplemental Information

cc w/ encl: Electronic Distribution

C. Schwarz -3-

DISTRIBUTION:

Regional Administrator (Elmo.Collins@nrc.gov)

Deputy Regional Administrator (Art.Howell@nrc.gov)

DRP Director (Kriss.Kennedy@nrc.gov )

DRP Deputy Director (Troy.Pruett@nrc.gov)

DRS Director (Anton.Vegel@nrc.gov )

DRS Deputy Director (Tom.Blount@nrc.gov)

Senior Resident Inspector (Alfred.Sanchez@nrc.gov)

Resident Inspector (Jeff.Rotton@nrc.gov )

Resident Inspector (William.Schaup@nrc.gov)

Branch Chief, DRP/E (Don.Allen@nrc.gov)

Senior Project Engineer, DRP/E (Ray.Azua@nrc.gov)

Project Engineer (Jim.Melfi@nrc.gov)

Project Engineer (Dan.Bradley@nrc.gov)

ANO Administrative Assistant (Gloria.Hatfield@nrc.gov)

Public Affairs Officer (Victor.Dricks@nrc.gov)

Public Affairs Officer (Lara.Uselding@nrc.gov)

Project Manager (Kaly.Kalyanam@nrc.gov)

Branch Chief, DRS/TSB (Ryan.Alexander@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

Congressional Affairs Officer (Jenny.Weil@nrc.gov)

ACES (Heather.Gepford@nrc.gov)

OEMail Resource

ROPreports

OEDO RIV Coordinator (Lydia.Chang@nrc.gov)

NSIR/DPR/EP (Eric.Schrader@nrc.gov)

Regional State Liaison Officer (Bill.Maier@nrc.gov)

R:\_REACTORS\_ANO\2011\ANO2011005-RP-AS.docx

ML120450828

SUNSI Rev Compl. Yes No ADAMS Yes No Reviewer Initials DBA

Publicly Avail Yes No Sensitive Yes No Sens. Type Initials DBA

SRI:DRP/E RI:DRP/E RI:DRP/E SPE:DRP/E C:DRS/EB1 C:DRS/EB2

FSanchez JRotton WSchaup RAzua TFarnholtz GMiller

/RA via Email/ /RA via /RA via /RA/ /RA/ /RA/

Email/ Email/

2/10/12 2/10/12 2/10/12 2/10/12 2/13/12 2/13/12

C:DRS/OB C:DRS/PSB1 C:DRS/PSB2 C:DRS/TSB C:DRP/E

MHaire MHay GWerner DPowers DAllen

/RA/ /RA/ /RA/ /RA/ /RA/

2/13/12 2/13/12 2/13/12 2/13/12 2/14/12

OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000313; 05000368

License: DPR-51; NPF-6

Report: 05000313/2011005; 05000368/2011005

Licensee: Entergy Operations Inc.

Facility: Arkansas Nuclear One, Units 1 and 2

Location: Junction of Hwy. 64 West and Hwy. 333 South

Russellville, Arkansas

Dates: October 1 through December 31, 2011

Inspectors: A. Sanchez, Senior Resident Inspector

J. Rotton, Resident Inspector

W. Schaup, Resident Inspector

G. Guerra, CHP, Emergency Preparedness Inspector

R. Kopriva, Senior Reactor Inspector

M. Williams, Reactor Inspector

Approved By: Don Allen, Chief, Project Branch E

Division of Reactor Projects

-1- Enclosure

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 inspections by region-based inspectors. 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 process

does not apply may be Green or be assigned a severity level after NRC management review.

The NRC's program for overseeing the safe operation of commercial nuclear power reactors is

described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

A. NRC-Identified Findings and Self-Revealing Findings

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 licensees 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 actions 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

affects 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-4A 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

-2- Enclosure

VCH-4B 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 licensees

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 affects 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

-3- Enclosure

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

affects 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).

-4- Enclosure

Cornerstone: Barrier Integrity

  • 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-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 requires a torque amplifying

device to operate. The issue was entered into the licensees 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 affects 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 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 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).

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

-5- Enclosure

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 affects 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

licensees 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

-6- Enclosure

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 licensees corrective action program. These violations and

corrective action tracking numbers (condition report numbers) are listed in

Section 4OA7.

-7- Enclosure

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.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

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.

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 their

corrective action program in accordance with station corrective action procedures. The

inspectors reviews focused specifically on the following plant systems:

-8- Enclosure

  • 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. Findings

No findings were identified.

1R04 Equipment Alignments (71111.04)

.1 Partial Walkdown

a. Inspection Scope

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

systems:

  • 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 generator 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 samples as

defined in Inspection Procedure 71111.04-05.

-9- Enclosure

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

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 licensees 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.

These activities constitute completion of one (1) complete system walkdown sample as

defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection (71111.05)

Quarterly Fire Inspection Tours

a. Inspection Scope

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:

  • 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

- 10 - Enclosure

  • 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 licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk

as documented in the plants Individual Plant Examination of External Events with later

additional insights, their potential to affect equipment that could initiate or mitigate a

plant transient, or their impact on the plants ability to respond to a security event. Using

the documents listed in the attachment, the inspectors verified that fire hoses and

extinguishers were in their designated locations and available for immediate use; that

fire detectors and sprinklers were unobstructed; that transient material loading was

within the analyzed limits; and fire doors, dampers, and penetration seals appeared to

be in satisfactory condition. The inspectors also verified that minor issues identified

during the inspection were entered into the licensees corrective action program.

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

These activities constitute completion of four (4) quarterly fire-protection inspection

samples as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope

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.

- 11 - Enclosure

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

samples and one (1) bunker/manhole sample as defined in Inspection Procedure

71111.06-05.

b. Findings

No findings were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

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 licensees 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.

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.

- 12 - Enclosure

1R08 Inservice Inspection Activities (71111.08)

.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. Inspection Scope

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.

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE

Reactor Coolant Let-down Heat Exchanger, Solvent Soluble

System Drawing # 6600-M1J-3-7, Contrasting Dye

Component ID # 37-005, Liquid Penetrant Examination

Penetrant Exam # 1-ISI-PT-11- (PT)

003

Reactor Coolant Component ID: 1FCB-1 Piping, Solvent Soluble

Core Flood Description: FW-11C1, Drawing # Contrasting Dye

CF-200, Liquid Penentrant Exam Penetrant Examination

  1. 1-BOP-PT-11-012 (PT)

Reactor Coolant Component ID: 1FCB-1 Piping, Solvent Soluble

Core Flood Description: FW-12C1, Drawing # Contrasting Dye

CF-200, Liquid Penentrant Exam Penetrant Examination

  1. 1-BOP-PT-11-012 (PT)

Containment Containment building spray valve Radiograph Examination

Building Spray and elbow, Drawing # 5-BS-1, (RT)

System Component ID # BS-4B,

Radiograph Exam # 1-BOP-RT-

11-016

Reactor Coolant Steam Generator A, E-24A Lower Ultrasonic Examination

System Head to Lower Ring Head Weld. (UT)

Drawing # M1D-295, Component

  1. 03-102, Ultrasonic Exam # 1-

ISI-UT-11-012

Reactor Coolant Steam Generator A, E-24A Lower Ultrasonic Examination

System Head Ring to Lower Tubesheet (UT)

Weld. Drawing # M1D-295,

Component # 03-103, Ultrasonic

- 13 - Enclosure

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE

Exam # 1-ISI-UT-11-014

High Pressure Pipe to Elbow Circumference Ultrasonic Examination

Injection System Seam. Drawing # 17-MU-27 (UT)

Sheet 1. Component ID # 23-063,

Ultrasonic Exam # 1-ISI-UT-11-

008

High Pressure Pipe to Pipe Circumference Ultrasonic Examination

Injection System Seam. Drawing # 17-MU-27 (UT)

Sheet 1. Component ID # 23-107,

Ultrasonic Exam # 1-ISI-UT-11-

009

Steam Generator Letdown pipe, Elbow to Pipe Ultrasonic Examination

Seam. Drawing # 17-MU-1 Sheet (UT)

2, Component ID # 24-009,

Ultrasonic Exam # 1-ISI-UT-11-

010

Reactor Coolant Pressurizer Relief Nozzle Enhanced Visual

System Between Z-W Axis. Examination (VT-1)

Drawing # M1G-69, Component

ID # 05-15IR, Visual

Exam # 1-ISI-VT-11-034

Steam Generator Steam Generator B Upper Head Visual Examination (VT-1)

Manhole studs, washers, and

nuts, Drawing # M1D-295 and

M1D-251, Component ID # 03-

120, Visual Exam # 1-ISI-VT-11-

069

Steam Generator Steam Generator B Lower Head Visual Examination (VT-1)

Manhole studs, washers, and

nuts, Drawing # M1D-295 and

M1D-251, Component ID # 03-

119, Visual Exam # 1-ISI-VT-11-

068

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

System 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

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

- 14 - Enclosure

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 Reactor lower head bottom Enhanced Visual

System mounted in-core instrumentation Examination (VT-2)

Alloy 600 bare metal inspection,

Drawing # M-77 and M1B-231,

Visual Exam # 1-ISI-VT-11-053

Service Water Spring Can Hanger HCD-111-H3. Visual Examination (VT-3)

System Drawing # 13-SW-110,

Component # 54-059, Visual

Exam # 1-ISI-VT-11-059

The inspectors reviewed records for the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE

Main Steam E-24A Steam outlet nozzle to Dry, Color Contrast,

System shell weld (@26 degrees), Magnetic Particle

Drawing # M1D-295m Examination (MT)

Component # 03-117, Magnetic

Particle Exam # 1-ISI-MT-11-001

Containment Containment building spray valve Radiograph Examination

Building Spray and elbow, Drawing # ISO 5-BS-1 (RT)

System and 5-BS-101, Component ID #

BS-4B, Radiograph Exam # 1-

BOP-RT-11-012

Containment Containment building spray valve Radiograph Examination

Building Spray and elbow, Drawing # ISO 5-BS-1 (RT)

System and 5-BS-101, Component ID #

BS-4B, Radiograph Exam # 1-

BOP-RT-11-013

Containment Containment building spray valve Radiograph examination

Building Spray and elbow, Drawing # ISO 5-BS-1 (RT)

System and 5-BS-101, Component ID #

BS-4B, Radiograph

Exam # 1-BOP-RT-11-014

Reactor Coolant Reactor lower head bottom Enhanced Visual

System mounted in-core instrumentation Examination (VT-2)

- 15 - Enclosure

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE

Alloy 600 bare metal inspection,

Drawing # M-77 and M1B-231,

Visual Exam # 1-ISI-VT-11-053

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 Component ID: 1FCB-1 Piping, Tungsten Inert Gas -

Drain Tank Description: FW-12C1, GTAW

Drawing # CF-200

Reactor Building BS-4B - 8 inch,150 pound, Tungsten Inert Gas -

Spray tilting disc check valve, GTAW

Drawing # M-236.

The inspectors reviewed records for the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE

Reactor Coolant Component ID: 1FCB-1 Piping, Tungsten Inert Gas -

Drain Tank Description: FW-11C1, GTAW

Drawing # CF-200

Reactor Building BS-4B - 8 inch,150 pound, Tungsten Inert Gas -

Spray tilting disc check valve. Weld GTAW

attaching 45° elbow to

downstream pipe, Drawing #

M-236.

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.

- 16 - Enclosure

These actions constitute completion of the requirements for Section 02.01.

b. Findings

No findings were identified.

.2 Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)

a. Inspection Scope

The inspectors reviewed the results of the licensees 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 licensees 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 licensees 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. Findings

No findings were identified.

- 17 - Enclosure

.4 Steam Generator Tube Inspection Activities (71111.08-02.04)

a. Inspection Scope

Arkansas Nuclear One - Unit One (ANO1) replacement steam generators (1E-24 A&B)

are Framatome Enhanced Once Through Steam Generators (EOTSGs). 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.

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

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

- 18 - Enclosure

Tube Support Plate Wear (Indications)

Steam Generator Percent Through Percent Through Percent Through

ID Wall Wall 20-39 Wall 40-100

1-19 Percent Percent 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:

Refuel outage 1R21 was the fourth inspection where bowing had 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-

- 19 - Enclosure

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.

This was the first time that bowing had 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 Generator 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. Findings

No findings were identified.

.5 Identification and Resolution of Problems (71111.08-02.05)

a. Inspection Scope

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.

These actions constitute completion of the requirements of Section 02.05.

- 20 - Enclosure

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program (71111.11)

a. Inspection Scope

On November 29, 2011, the inspectors observed a Unit 2 crew of licensed operators in

the plants simulator to verify that operator performance was adequate, evaluators were

identifying and documenting crew performance problems and training was being

conducted in accordance with licensee procedures. The inspectors evaluated the

following areas:

  • Licensed operator performance
  • Crews clarity and formality of communications
  • Crews ability to take timely actions in the conservative direction
  • Crews prioritization, interpretation, and verification of annunciator alarms
  • Crews correct use and implementation of abnormal and emergency procedures
  • Control board manipulations
  • Oversight and direction from supervisors
  • Crews ability to identify and implement appropriate technical specification actions

and emergency plan actions and notifications

The inspectors compared the crews performance in these areas to 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. Findings

No findings were identified.

- 21 - Enclosure

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk

significant systems:

  • November 29, 2011, Alternate AC generator
  • December 15, 2011, Unit 1 L-1 Turbine building crane
  • 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
  • Characterizing system reliability issues for performance
  • Charging unavailability for performance
  • Trending key parameters for condition monitoring
  • 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.

- 22 - Enclosure

These activities constitute completion of four (4) quarterly maintenance effectiveness

samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

a. Inspection Scope

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:

  • 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 samples as defined in Inspection

Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments (71111.15)

a. Inspection Scope

The inspectors reviewed the following issues:

- 23 - Enclosure

  • June 15, 2011, Unit 1 manhole MH-9 broken fire barrier inside manhole

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 personnels evaluations to determine whether the components or systems were

operable. Where compensatory measures were required to maintain operability, the

inspectors determined whether the measures in place would function as intended and

were properly controlled. The inspectors determined, where appropriate, compliance

with bounding limitations associated with the evaluations. Additionally, the inspectors

also reviewed a sampling of corrective action documents to verify that the licensee was

identifying and correcting any deficiencies associated with operability evaluations.

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

These activities constitute completion of four (4) operability evaluations inspection

sample(s) as defined in Inspection Procedure 71111.15-05.

b. Findings

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 licensees 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.

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

- 24 - Enclosure

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 specification

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 licensees 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 affects 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 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

inspectors reviewed the engineering change EC-25691, Prepare EC markup to

- 25 - Enclosure

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 specifications 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 (71111.18)

.1 Temporary Modifications

a. Inspection Scope

To verify that the safety functions of important safety systems were not degraded, the

inspectors reviewed the following temporary modifications:

  • November 3, 2011, Unit 1, temporary electrical power for spent fuel pool cooling

P-40A

- 26 - Enclosure

protection calculator C

The inspectors reviewed the temporary modifications 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 on

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) samples for temporary plant

modifications as defined in Inspection Procedure 71111.18-05.

b. Findings

No findings were identified.

.2 Permanent Modifications

a. Inspection Scope

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.

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.

- 27 - Enclosure

b. Findings

No findings were identified.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed the following postmaintenance activities to verify that

procedures and test activities were adequate to ensure system operability and functional

capability:

  • 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

samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

- 28 - Enclosure

1R20 Refueling and Other Outage Activities (71111.20)

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Unit 1

1R23 refueling outage, conducted October 16, 2011, through November 22, 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.

  • 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.

  • Verification that outage work was not impacting the ability of the operators to operate

the spent fuel pool cooling system.

means for inventory addition, and controls to prevent inventory loss.

  • Controls over activities that could affect reactivity.
  • 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.

- 29 - Enclosure

  • 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. Findings

(1) Failure to Implement Procedure Results in Lowering Spent Fuel Pool Level by 0.6 Feet

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 directed 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 tube

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.

- 30 - Enclosure

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 affects 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, stated 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

- 31 - Enclosure

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 licensees 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) detailed

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 this 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.

- 32 - Enclosure

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 pumps 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

affects 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 nonconformances 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

- 33 - Enclosure

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 an

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

- 34 - Enclosure

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 their 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 affects 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

- 35 - Enclosure

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 defueled window to address

the overload issue.

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

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

- 36 - Enclosure

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 licensees 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 licensees 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

- 37 - Enclosure

the performance deficiency could become a more safety significant issue. Specifically,

the licensees 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 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).

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 (71111.22)

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

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  • 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

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 engineered 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 samples

as defined in Inspection Procedure 71111.22-05.

b. Findings

No findings were identified.

- 39 - Enclosure

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)

a. Inspection Scope

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.

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. Findings

No findings were identified.

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope

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 crews

performance and ensure that the licensee evaluators noted the same issues and entered

them into the corrective action program. As part of the inspection, the inspectors

reviewed the scenario package and other documents listed in the attachment.

These activities constitute completion of one (1) sample as defined in Inspection

Procedure 71114.06-05.

- 40 - Enclosure

b. Findings

No findings were identified.

4. OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency

Preparedness, Public Radiation Safety, Occupational Radiation Safety, and

Physical Protection

4OA1 Performance Indicator Verification (71151)

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the

licensee for the third Quarter 2011 performance indicators for any obvious

inconsistencies prior to its public release in accordance with Inspection Manual

Chapter 0608, Performance Indicator Program.

This review was performed as part of the inspectors normal plant status activities and,

as such, did not constitute a separate inspection sample.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Emergency ac Power System (MS06)

a. Inspection Scope

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

licensees 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 licensees issue report

database to determine if any problems had been identified with the performance

indicator data collected or transmitted for this indicator and none were identified.

Specific documents reviewed are described in the attachment to this report.

- 41 - Enclosure

These activities constitute completion of two (2) mitigating systems performance index -

emergency ac power system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)

a. Inspection Scope

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

licensees operator narrative logs, issue reports, mitigating systems performance index

derivation reports, event reports, and NRC integrated inspection reports for the period of

October 2010 through September 2011 to validate the accuracy of the submittals. The

inspectors reviewed the mitigating systems performance index component risk

coefficient to determine if it had changed by more than 25 percent in value since the

previous inspection, and if so, that the change was in accordance with applicable NEI

guidance. The inspectors also reviewed the licensees issue report database to

determine if any problems had been identified with the performance indicator data

collected or transmitted for this indicator and none were identified. Specific documents

reviewed are described in the attachment to this report.

These activities constitute completion of two (2) mitigating systems performance index -

high pressure injection system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution (71152)

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of

this report, the inspectors routinely reviewed issues during baseline inspection activities

and plant status reviews to verify that they were being entered into the licensees

corrective action program at an appropriate threshold, that adequate attention was being

given to timely corrective actions, and that adverse trends were identified and

addressed. The inspectors reviewed attributes that included the complete and accurate

- 42 - Enclosure

identification of the problem; the timely correction, commensurate with the safety

significance; the evaluation and disposition of performance issues, generic implications,

common causes, contributing factors, root causes, extent of condition reviews, and

previous occurrences reviews; and the classification, prioritization, focus, and timeliness

of corrective actions. Minor issues entered into the licensees corrective action program

because of the inspectors observations are included in the attached list of documents

reviewed.

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. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific

human performance issues for follow-up, the inspectors performed a daily screening of

items entered into the licensees corrective action program. The inspectors

accomplished this through review of the stations daily corrective action documents.

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. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees corrective action program and

associated documents to identify trends that could indicate the existence of a more

significant safety issue. The inspectors focused their review on repetitive equipment

issues, but also considered the results of daily corrective action item screening

discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human

performance results. The inspectors nominally considered the 6-month period of June

2011 through December 2011 although some examples expanded beyond those dates

where the scope of the trend warranted.

The inspectors also included issues documented outside the normal corrective action

program in major equipment problem lists, repetitive and/or rework maintenance lists,

- 43 - Enclosure

departmental problem/challenges lists, system health reports, quality assurance

audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the

licensees corrective action program trending reports. Corrective actions associated with

a sample of the issues identified in the licensees trending reports were reviewed for

adequacy.

These activities constitute completion of one (1) single semi-annual trend inspection

sample as defined in Inspection Procedure 71152-05.

b. Findings and Observations

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.

.4 Selected Issue Follow-up Inspection

a. Inspection Scope

During a review of items entered in the licensees 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 diesels functionality

and the high risk significance associated with potential loss of functionality of the

alternate AC diesel generator.

These activities constitute completion of one (1) in-depth problem identification and

resolution sample as defined in Inspection Procedure 71152-05.

b. Findings

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-1015.049 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 that plant components were in required

positions.

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 run 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

- 44 - Enclosure

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 this 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

- 45 - Enclosure

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

deficiency. The performance deficiency is more than minor because it is associated with

the configuration control attribute of the Mitigating Systems cornerstone and adversely

affects 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 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 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 licensees 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 control. Station

procedure OP-1015.049, Configuration Control Program, Revision 1, step 6.1 stated

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

- 46 - Enclosure

noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000313/2011005-06, Failure to Adequately Implement the Configuration Control

Program.

.5 In-depth Review of Operator Workarounds

a. Inspection Scope

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.

b. Findings

No findings were identified.

4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)

.1 (Closed) LER 05000368/2009003 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 Mode 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-2-2009-2357. A

licensee identified noncited violation was documented in Inspection Report 05000368/2009004 for this issue. This licensee event report is closed.

- 47 - Enclosure

.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 loss 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

- 48 - Enclosure

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

licensees procedures and processes for filling and venting ECCS systems. This

inspection effort counts towards the completion of TI 2515/177 which will be closed 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 licensees emergency plan and emergency action levels to

Mr. R. Holeyfield, Manager, Emergency Preparedness, and other members of the licensees

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, 2012, 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.

established, implemented, and maintained covering the following activitiesthe

- 49 - Enclosure

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.

established, implemented, and maintained covering the following activitiesthe

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.

- 50 - Enclosure

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, Engineering

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

Exceeded Technical Specification Allowed Completion Time for

05000313/2011005-01 NCV

Electrical Power Systems (Section 1R15)

Failure to Implement Procedure Results in Lowering Spent Fuel

05000313/2011005-02 NCV

Pool Level by 0.6 Feet (Section 1R20(1))

Failure to Identify and Correct Unit 1 Service Water Pump Column

05000313/2011005-03 NCV

Protective Wrap Installation Deficiencies (Section 1R20(2))05000313/2011005-04 NCV Failure to Identify and Correct a Condition Adverse to Quality

A-1 Attachment

Opened and Closed

Resulted in Dropping a Fuel Bundle Approximately One Inch

(Section 1R20(3))

Failure to Take Adequate Corrective Actions for Known Fuel

05000313/2011005-05 FIN

Transfer System Deficiencies (Section 1R20(4))

Failure to Adequately Implement the Configuration Control

05000313/2011005-06 NCV

Program (Section 4OA2.4)

Closed

Steam Generator Tube Exceeding Technical Specification

Plugging Criteria Remained in Service During Previous Cycles as

05000368/2009003 LER

a Result of the Failure to Use Proper Independent Verification

Containment Building Penetration Isolation Valves Open During

Core Alterations without Application of Administrative Controls

05000368/2009002 LER Required by Technical Specifications Due to Inadequate

Procedural Instructions

Emergency Diesel Automatic Actuation While Performing Offsite

05000368/2009004 LER Power Transfer Testing Due to a High Resistance Contact

Supplying Voltage to a Synchronizing Check Relay

A-2 Attachment

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

PROCEDURES

NUMBER TITLE REVISION

OP-1104.039 Plant Heating and Cold Weather Operations 22

OP-2106.032 Unit 2 Two Freeze Protection Guide 22

Section 1R04: Equipment Alignment

PROCEDURES

NUMBER TITLE REVISION

OP-1104.029 Unit 1 Service and Auxiliary Cooling Water System 55

OP-1104.036 Unit 1 Emergency Diesel Generator Operation 59

OP-2104.037 Alternate AC Diesel Generator 22

OP-1104.032 Unit 1 Fire Protection Systems 68

OP-2104.032 Unit 2 Fire Protection Systems Operations 32

DRAWINGS

NUMBER TITLE REVISION

M-210 Service Water 150

M-217 Emergency Diesel Generator and Fuel Oil System 89

M-2241 Alternate AC Generator System 3

M-2219 Fire Water System Pipe and Instrument Diagram 61

Sheet 1

M-2219 Fire Water System Pipe and Instrument Diagram 69

Sheet 2

M-2219 Deluge Valve Detail 35

Sheet 4

M-2219 Outside Fire Loop 50

Sheet 5

M-2219 Deluge Valve Detail 15

Sheet 7

A-3 Attachment

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

STM-1-42 Unit 1 Service and Auxiliary Cooling Water 20

STM-1-31 Unit 1 Emergency Diesel Generators 12

STM-2-33 Unit 2 Alternate AC Diesel Generator 21

Section 1R05: Fire Protection

PROCEDURES

NUMBER TITLE REVISION

FHA ANO Fire Hazard Analysis 13

PFP-U1 ANO Pre-Fire Plan Unit 1 13

PFP-U2 ANO Pre-Fire Plan Unit 2 10

DRAWINGS

NUMBER TITLE REVISION

FZ-1063 Unit 1 Fire Zone Detail - Reactor Building 3

FZ-1064 Unit 1 Fire Zone Detail - Reactor Building 3

FZ-1065 Unit 1 Fire Zone Detail - Reactor Building 3

FZ-1066 Unit 1 Fire Zone Detail - Reactor Building 3

FZ-1067 Unit 1 Fire Zone Detail - Reactor Building 3

FZ-2044 Unit 2 Fire Zone Detail - Electrical Switchgear, Feedwater 1

Heaters, and Turbine areas

FZ-2025 Unit 2 Fire Zone Detail - Electrical Equipment (motor 2

generator sets) room

FZ-1030 Unit 1 Service Water Intake Structure 2

Section 1R06: Flood Protection Measures

PROCEDURES

NUMBER TITLE REVISION

ULD-0-TOP-17 ANO Topical Flooding 0

A-4 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 2nd Iteration

ULD-1-SYS-01 ANO Unit 1 Emergency Diesel Generator 5

ULD-0-TOP-02 Fire Protection Topical 4

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 1R07: 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 21

CONDITION REPORTS

CR-ANO-1-2011-2134 CR-ANO-1-2011-2014 CR-ANO-1-2011-1750 CR-ANO-1-2011-1712

Section 1R08: Inservice Inspection Activities

DOCUMENTS

NUMBER TITLE REVISION /

DATE

Entergy Steam Generator Degradation Assessment: Plant and 0

Unit - Arkansas Nuclear One Unit One, Refueling Outage:

1R23

Snapshot Assessment / Benchmark On: August 31,

Pre-NRC Inspection - In-service Inspection (ISI) 2011

1R23

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

A-5 Attachment

Section 1R08: Inservice Inspection Activities

DOCUMENTS

NUMBER TITLE REVISION /

DATE

1R20 Cycle Report Spring 2007

1032.037 Inspection And Identification Of Boric Acid Leaks For ANO-1 5

and ANO-2

1103.013 RCS Leak Detection 35

1CAN060902 Request for Alternative - Implementation of a Risk-Informed June 11, 2009

Inservice Inspection Program Based on ASME Code Case N-

716, Arkansas Nuclear One, Unit 1, Docket No. 50-313

License No. DPR-51

1CNA030901 Arkansas Nuclear One, Unit 1, Grand Gulf Nuclear Station, March 6, 2009

River Bend 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)

1CNA061001 Arkansas Nuclear One, Unit No. 1 -Request For Alternative June 2, 2010

AN01-ISI-014 Re: Implementation Of a Risk-Informed

Inservice Inspection Program Based on ASME Code

Case N-716 (TAC No. ME1488)

20004-017 ENGINEERING INFORMATION RECORD, Document No.: 51 March 2010

- 9135783 - 000, Technical Summary of Steam Generator

Eddy Current Examinations at Arkansas Nuclear One, 1R22

51-9135783-000 Areva NP Inc, Engineering Information Record, Technical March 2010

Summary of Steam Generator Eddy Current Examinations at

Arkansas Nuclear One, 1R22.

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

00016

EN-DC-319 Inspection and evaluation of Boric Acid Leaks 7

EN-DC-319 Inspection and evaluation of Boric Acid Leaks 6

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

00090 Assessment 2009

LO-ALO-2010- Assessment Report: Welding Program Assessment August 2011

00056

A-6 Attachment

NDE PROCEDURES

NUMBER TITLE REVISION

CEP-NDE-0255 Radiographic Examination ASME, ANSI,AWS Welds and 6

Components

CEP-NDE-0400 Ultrasonic Examination 3

CEP-NDE-0404 Manual Ultrasonic Examination of Ferritic Piping Welds 5

(ASME XI)

CEP-NDE-0407 Straight Beam Ultrasonic Examinations of Bolts and Studs 3

(ASME XI)

CEP-NDE-0423 Manual Ultrasonic Examination of Austenitic Piping Welds 5

(ASME XI)

CEP-NDE-0497 Manual Ultrasonic Examination of Welds in Vessels (Non- 5

App. VIII)

CEP-NDE-0641 Liquid Penetrant Examination (PT) for ASME Section XI 7

CEP-NDE-0731 Magnetic Particle Examination (MT) for ASME Section XI 3

CEP-NDE-0901 VT-1 Examination 4

CEP-NDE-0902 VT-2 Examination 7

CEP-NDE-0903 VT-3 Examination 5

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

A-7 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 1

EN-DC-204 Maintenance Rule Scope and Basis 2

EN-DC-205 Maintenance Rule Monitoring 3

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

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

OP-2104.037 Alternate AC Diesel Generator Operations 21

MISCELLANEOUS DOCUMENTS

NUMBER TITLE DATE

Maintenance Rule Database Scoping and October 12, 2011

Performance Criteria - Unit 1 Alternate AC diesel

generator

Unit 1 Alternate AC diesel generator Functional October 12, 2011

Failure Determination Report

Maintenance Rule Database Scoping and November 15, 2011

Performance Criteria - Unit 1 Turbine Building

Unit 1 Turbine Building Functional Failure November 15, 2011

Determination Report

Unit 1 Reactor Building Spray - Maintenance Rule November 28, 2011

Database Scoping and Performance Criteria

Unit 1 Reactor Building Spray - Maintenance Rule November 28, 2011

Functional Failure Determination Report

CONDITION REPORTS

CR-ANO-C-2011-1639 CR-ANO-C-2011-1971 CR-ANO-C-2011-1862 CR-ANO-1-2011-0567

CR-ANO-C-2011-0061 CR-ANO-1-2011-1617 CR-ANO-1-2011-2075 CR-ANO-1-2011-0588

CR-ANO-1-2011-0999

A-8 Attachment

Section 1R13: Maintenance Risk Assessment and Emergent Work Controls

PROCEDURE

NUMBER TITLE REVISION

OP-1203.025 Natural Emergencies 35

CONDITION REPORTS

CR-ANO-C-2011-2952

Section 1R15: Operability Evaluations

PROCEDURES

NUMBER TITLE REVISION

EN-OP-104 Operability Evaluations 5

OP-1105.001 Unit 1 Nuclear Instrumentation and Reactor Protection 25

System Operating Procedure

CALCULATIONS

NUMBER TITLE REVISION

CALC-ANO1-NE- ANO Unit 1 Cycle 24 Core Operating Limits Report 3

11-00002

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

STM-1-63 Unit 1 Reactor Protection System 9

CONDITION REPORTS

CR-ANO-1-2011-1655 CR-ANO-1-2011-1659 CR-ANO-1-2011-1667 CR-ANO-1-2010-3653

CR-ANO-1-2011-1672 CR-ANO-1-2011-3044 CR-ANO-1-2011-3183 CR-ANO-1-2011-0896

A-9 Attachment

Section 1R18: Plant Modifications

PROCEDURES

NUMBER TITLE REVISION

EN-DC-115 Engineering Change Process 12

EN-DC-136 Temporary Modifications 6

ENGINEERING CHANGE DOCUMENTS

EC-31408 EC-30016

WORK ORDERS

00277055 00279037

Section 1R19: Postmaintenance Testing

PROCEDURES

NUMBER TITLE REVISION

OP-2304.039 Unit 2 Plant Protection System Channel C Test 47

OP-1305.007 RB Isolation and Miscellaneous Valve Stroke Test 39

EN-MA-101 Fundamentals of Maintenance 9

EN-WM-102 Work Implementation and Closeout 6

EN-WM-105 Planning 9

EN-WM-107 Post Maintenance Testing 3

WORK ORDERS

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 51

OP-1506.001 Fuel and Control Component Handling 41

OP-1502.004 Control of Unit 1 Refueling 49

A-10 Attachment

Section 1R20: Refueling and Other Outage Activities

PROCEDURES

NUMBER TITLE REVISION /

DATE

OP-1502.003 Refueling Equipment and Operator Checkouts 35

OP-1103.011 Draining and N2 Blanketing the RCS 39

EN-OM-123 Fatigue Management Program 3

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 4

STM-1-51-2 Spent Fuel Handling & SFP Area Equipment 10

STM-1-51-3 Fuel Transfer System 2

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 35

OP-1104.002 Unit 1 Makeup and Purification System Operation 72

OP-1104.027 Unit 1 Battery and Switchgear Emergency Cooling System 40

OP-2305.017 Local Leak Rate Testing 28

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-1-2011-2700

CR-ANO-1-2011-2516 CR-ANO-1-2011-2130

A-11 Attachment

WORK ORDERS

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 42

OP-1903.011Y Emergency Class Initial Notification Message 40

Section 4OA1: Performance Indicator Verification

PROCEDURES

NUMBER TITLE REVISION

EN-LI-114 Performance Indicator Process 4

MISCELLANEOUS DOCUMENTS

NUMBER TITLE DATE

Unit 1 MSPI Derivation Report - Emergency AC Power October 28, 2011

System - Unavailability Index

Unit 1 MSPI Derivation Report - Emergency AC Power October 28, 2011

System - Unreliability Index

Unit 1 Emergency Diesel Generator 1 Conditional October 28, 2011

Probability Data

Unit 1 Emergency Diesel Generator 2 Conditional October 28, 2011

Probability Data

Unit 1 MSPI Derivation Report - High Pressure Injection October 28, 2011

System - Unavailability Index

Unit 1 MSPI Derivation Report - High Pressure Injection October 28, 2011

System - Unreliability Index

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

Probability Data

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

Probability Data

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

Probability Data

A-12 Attachment

Section 4OA2: Identification and Resolution of Problems

PROCEDURES

NUMBER TITLE REVISION

COPD-001 Operations Expectations and Standards 55

COPD-020 ANO Operations Concerns Program 10

EN-FAP-OP-006 Operator Aggregate Impact Index Performance Indicator 6

OP-2304.258 Unit 2 Escape Airlock Leak Rate Test 17

OP-2305.017 Local Leak Rate Testing 26

OP-2411.029 Emergency Air Lock Inspection, Lubrication and Chalk Test 5

OP-1015.001 Conduct of Operations 89

OP-1015.049 Configuration Control Program 1

OP-1103.002 Draining and Nitrogen Blanketing the Reactor Coolant 41

System

OP-1103.011 Filling and Venting the Reactor Coolant System 37

OP-1104.004 Decay Heat Removal Operating Procedure 94

OP-1104.002 Unit 1 Makeup and Purification System Operation 72

DRAWINGS

NUMBER TITLE REVISION

DWG 30970 Emergency Access Airlock - General Arrangement 0

DWG 30970 Emergency Access Airlock - General Assembly 0

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

A-13 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-2-2008-2360 CR-ANO-2-2009-0176 CR-ANO-2-2011-1663

CR-ANO-2-2011-3250 CR-ANO-2-2009-3566 CR-ANO-2-2010-0923 CR-ANO-2-2011-1687

CR-ANO-2-2010-0056 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

A-14 Attachment