Text

IR 05000445-13-004, 05000446-13-004; on 6/27/2013 - 9/25/2013; Comanche Peak Nuclear Power Plant, Units 1 & 2, Integrated Inspection Report; Equipment Alignments, Maintenance Effectiveness, Operability Evaluations and Functionality Assessme
	ML13310C184
Person / Time
Site:	Comanche Peak
Issue date:	11/06/2013
From:	Webb Patricia Walker; NRC/RGN-IV/DRP/RPB-A
To:	Flores R; Luminant Generation Co
References
	IR-13-004
	Download: ML13310C184 (47)
	v • d • e

UNITE D S TATE S

NUC LEAR RE GULATOR Y C OMMI S SI ON

R E G IO N I V

1600 EAST LAMAR BLVD

AR L I NGTON , TEXAS 7 601 1- 4511

November 6, 2013

Rafael Flores, Senior Vice President

and Chief Nuclear Officer

Luminant Generation Company, LLC

Comanche Peak Nuclear Power Plant

P.O. Box 1002

Glen Rose, TX 76043

Subject: COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION

REPORT 05000445/2013004 AND 05000446/2013004

Dear Mr. Flores:

On September 25, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an

inspection at your Comanche Peak Nuclear Power Plant, Units 1 and 2. On October 2, 2013,

the NRC inspectors discussed the results of this inspection with you and other members of your

staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented five findings of very low safety significance (Green) in this report.

Three of these findings involved violations of NRC requirements. Further, inspectors

documented a licensee-identified violation which was determined to be of very low safety

significance in this report. The NRC is treating these violations as non-cited violations (NCVs)

consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within

30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with

copies to the Regional Administrator, Region IV; the Director, Office of Enforcement,

U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident

inspector at the Comanche Peak Nuclear Power Plant, Units 1 and 2.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a

regulatory requirement in this report, you should provide a response within 30 days of the date

of this inspection report, with the basis for your disagreement, to the Regional Administrator,

Region IV; and the NRC resident inspector at the Comanche Peak Nuclear Power Plant,

Units 1 and 2.

R. Flores -2-

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections,

Exemptions, Requests for Withholding, 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

NRCs Public Document Room or from the Publicly Available Records (PARS) component of the

NRC's Agencywide Documents 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/

Wayne C. Walker, Branch Chief

Project Branch A

Division of Reactor Projects

Docket Nos.: 50-445, 50-446

License Nos.: NPF-87, NPF-89

Enclosure:

Inspection Report 05000445/2013004 and 05000446/2013004

w/Attachments:

1. Supplemental Information

2. Request for Information for the Temporary Instruction 2515-182,

Review of Implementation of the Industry Initiative to Control

Degradation of Underground Piping and Tanks Inspection

cc w/encl: Electronic Distribution for Comanche Peak

R. Flores -3-

Electronic distribution by RIV:

Regional Administrator (Marc.Dapas@nrc.gov)

Deputy Regional Administrator (Steven.Reynolds@nrc.gov)

DRP Director (Kriss.Kennedy@nrc.gov)

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

DRS Director (Tom.Blount@nrc.gov)

DRS Deputy Director (Jeff.Clark@nrc.gov)

Senior Resident Inspector (John.Kramer@nrc.gov)

Resident Inspector (Rayomand.Kumana@nrc.gov)

Branch Chief, DRP/A (Wayne.Walker@nrc.gov)

Senior Project Engineer, DRP/A (Ryan.Alexander@nrc.gov)

Project Engineer, DRP/A (Jason.Dykert@nrc.gov)

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

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

Project Manager (Balwant.Singal@nrc.gov)

Branch Chief, DRS/TSB (Ray.Kellar@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

ACES (R4Enforcement.Resource@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

Technical Support Assistant (Loretta.Williams@nrc.gov)

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

RIV/ETA: OEDO (Daniel.Rich@nrc.gov)

ROPreports

File located:R:\_REACTORS\CP2013004-RP-JGK.pdf

ADAMS Accession Number: ML13310C184

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

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

SRI:DRP/A RI:DRP/A SPE:DRP/A C:/DRS/TSB C:DRS/OB

JKramer RKumana RAlexander RKellar VGaddy

/RA/ E-Walker /RA/ RDA for /RA/ /RA/ /RA/

10/30/13 11/1/13 10/30/13 10/31/13 11/1/13

C:DRS/PSB1 C:DRS/PSB2 C:DRS/EB1 C:DRS/EB2 C:DRP/A

MHaire JDrake TFarnholtz GMiller WWalker

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

11/4/13 10/31/13 11/1/13 11/1/13 11/6/13

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

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 50-445, 50-446

License: NPF-87, NPF-89

Report: 05000445/2013004 and 05000446/2013004

Licensee: Luminant Generation Company LLC

Facility: Comanche Peak Nuclear Power Plant, Units 1 and 2

Location: FM-56, Glen Rose, Texas

Dates: June 27 through September 25, 2013

Inspectors: J. Kramer, Senior Resident Inspector

R. Kumana, Resident Inspector

S. Alferink, Reactor Inspector

I. Anchondo, Senior Reactor Inspector

S. Graves, Senior Reactor Inspector

D. Proulx, Senior Project Engineer

M. Williams, Reactor Inspector

Approved By: Wayne Walker, Chief, Project Branch A

Division of Reactor Projects

-1- Enclosure

SUMMARY OF FINDINGS

IR 05000445/2013004, 05000446/2013004; 6/27/2013 - 9/25/2013; Comanche Peak Nuclear

Power Plant, Units 1 and 2 Integrated Resident and Regional Report; Equipment Alignments,

Maintenance Effectiveness, Operability Evaluations and Functionality Assessments, Plant

Modifications, Post-Maintenance Testing

The report covered a 3-month period of inspection by resident inspectors and announced

baseline inspections by region-based inspectors. Three Green non-cited violations and two

Green findings 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: Initiating Events

Green. The inspectors reviewed a self-revealing finding for operations

personnel failure to follow instructions for the removal of the dissimilar metal

elbow when installing a pipe cap. As a result, the elbow eventually leaked,

reactor coolant system leakage increased, and a Unit 1 shutdown was needed to

correct the issue. The licensee entered the finding into the corrective action

program as Condition Report CR-2013-006795.

The finding was more than minor because it was associated with the human

performance attribute of the Initiating Events cornerstone and adversely affected

the cornerstone objective to limit the likelihood of those events that upset plant

stability and challenge critical safety functions during shutdown as well as power

operations. Using Inspection Manual Chapter 0609, Appendix A, The

Significance Determination Process for Findings At-Power, the finding was

determined to be of very low safety significance (Green) because the finding

could not result in exceeding the reactor coolant system leak rate for a small loss

of coolant accident and the finding would not have affected other systems used

to mitigate a loss of coolant accident resulting in a total loss of their function. The

finding had a human performance cross-cutting aspect associated with resources

because the environmental conditions impacted the ability of the operators to

correctly install the pipe cap H.3(a). (Section 1R15)

Green. The inspectors reviewed a self-revealing finding for the licensees failure

to ensure the heat exchanger tube plugging procedure was adequate. As a

result, auxiliary condenser plugs were improperly inserted and caused a tube

to leak. This caused high sodium levels in the steam generators and a Unit 2

power reduction from 100 percent to less than 50 percent power. The

licensee entered the finding into the corrective action program as Condition

Report CR-2012-011805.

-2-

The finding was more than minor because it was associated with the equipment

performance attribute of the Initiating Events cornerstone and adversely affected

the cornerstone objective, in that, it increased the likelihood of those events that

upset plant stability and challenge critical safety functions during power

operations. Using Inspection Manual Chapter 0609, Appendix A, The

Significance Determination Process for Findings At-Power, the finding was

determined to be of very low safety significance (Green) because the finding did

not cause a reactor trip and the loss of mitigation equipment. The finding has a

human performance cross-cutting aspect associated with work practices in that

the licensee supervision failed to provide appropriate oversight to the tube

plugging procedure and plugging activity H.4(c). (Section 1R18)

Cornerstone: Mitigating Systems

Green. The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure

to follow instructions and remove cables from containment as part of a

modification. As a result, portions of 12 cables totaling approximately 100 feet

in length wrapped with tape on the ends remained in containment and could

have been transported to the emergency sumps during an accident. The

licensee entered the finding into the corrective action program as Condition

Report CR-2013-009443.

The finding was more than minor because it was associated with the equipment

performance attribute of the mitigating systems cornerstone and adversely

affected the cornerstone objective to ensure the availability, reliability, and

capability of the emergency sumps. Using NRC Manual Chapter 0609,

Significance Determination Process, Appendix G, Shutdown Operations

Significance Determination Process, Attachment 1, Checklist 2, the finding was

determined to be of very low safety significance because the licensee maintained

adequate mitigation capability for the current plant state and the finding was not

characterized as a loss of control event. The finding has a human performance

cross-cutting aspect associated with work practices in that the maintenance

personnel did not involve supervision when they had questions concerning the

removal of the cables and proceeded in the face of uncertainty H.4(a).

(Section 1R04)

Green. The inspectors identified a non-cited violation of 10 CFR 50.65(a)(1) for

the licensees failure to establish performance goals and perform monitoring to

ensure the Unit 1 auxiliary feedwater system was capable of performing its

intended function. The licensee entered the finding into the corrective action

program as Condition Report CR-2013-010024.

This finding was more than minor because it was associated with the equipment

performance attribute of the Mitigating Systems cornerstone and adversely

affected the cornerstone objective to ensure the availability and reliability of

systems that respond to initiating events to prevent undesirable consequences.

Using Inspection Manual Chapter 0609, Appendix A, The Significance

Determination Process for Findings At-Power, the finding was determined to be

of very low safety significance (Green) because the finding was not a design or

qualification deficiency; did not represent an actual loss of safety function of a

system or train; and did not represent an actual loss of a technical specification

-3-

train for greater than its allowed outage time. The finding had a human

performance cross-cutting aspect associated with decision-making, in that, the

licensee failed to demonstrate that nuclear safety is the overriding priority by not

obtaining adequate interdisciplinary input when determining the auxiliary

feedwater maintenance rule status H.1(a). (Section 1R12)

Green. The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure

to follow procedures that require initiating a condition report for degradation to

safety-related equipment. During a surveillance activity, maintenance personnel

discovered that a reactor coolant pump under frequency relay was outside the

as-found setpoint tolerance for pick-up frequency and failed to enter the condition

into the corrective action program. As a result, the cause and effect of the

degraded condition was not evaluated and the relay again drifted outside the

setpoint tolerance. The licensee entered the finding into the corrective action

program as Condition Report CR-2013-010078.

The finding was more than minor because if the licensee continues to fail to

document degraded safety-related equipment in the corrective action database,

there is a potential that this could lead to a more significant safety concern, in

that the cause of the degradation will not be evaluated and corrected. Using

Inspection Manual Chapter 0609, Appendix A, The Significance Determination

Process for Findings At-Power, the finding was determined to be of very low

safety significance (Green) because the finding was not a design or qualification

deficiency; did not represent an actual loss of safety function of a system or train;

and did not represent an actual loss of a technical specification train for greater

than its allowed outage time. The finding has a human performance

cross-cutting aspect associated with resources in that the licensee failed to

provide adequate training to personnel performing maintenance H.2(b).

(Section 1R19)

B. Licensee-Identified Violations

A violation of very low safety significance was identified by the licensee and has been

reviewed by the inspectors. Corrective actions taken or planned by the licensee have

been entered into the licensees corrective action program. The violation and corrective

action tracking numbers are listed in Section 4OA7.

-4-

Plant Status

Unit 1 began the inspection period at approximately 100 percent power. On July 26, 2013, the

operators initiated a shutdown of Unit 1 to Mode 3 for a scheduled maintenance outage to repair

a leak associated with a seal injection drain line. The unit returned to service the following day

when the main generator output breakers were closed. On July 28, 2013, the unit returned to

approximately 100 percent power and operated at that power level for the remainder of the

inspection period.

Unit 2 began the inspection period at approximately 100 percent power and operated at that

power level for the remainder of the inspection period.

REPORT DETAILS

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

.1 Summer Readiness for Offsite and Alternate-AC Power Systems

a. Inspection Scope

The inspectors reviewed the licensees preparations for seasonal high grid loading. The

inspectors reviewed the licensees procedures and communications protocols to ensure

that they included measures to monitor and maintain availability and reliability of both the

off-site and alternate-ac power systems. The inspectors performed a walkdown of the

switchyard to observe the material condition of off-site power sources.

The inspectors also reviewed corrective action program items to verify that the licensee

was identifying summer readiness issues at an appropriate threshold and entering them

into its corrective action program for resolution.

These activities constitute completion of one summer readiness for off-site and

alternate-ac power systems sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

.2 Readiness to Cope with External Flooding

a. Inspection Scope

The inspectors performed a review of the Final Safety Analysis Report, the recent Safe

Shutdown Impoundment Dam Report, updated list of external flooding protection and

mitigation equipment, updated flooding walkdown issues list, and the latest revision of

the Post-Fukushima Flooding Reevaluation Report.

The inspectors also reviewed the corrective action program to determine if licensee

personnel identified and corrected flooding problems. The inspectors reviews focused

-5-

specifically on the turbine building doors below the probable maximum flood level, and

adjacent water intake and discharge structures.

These activities constitute completion of one readiness to cope with external flooding

sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignments (71111.04)

a. Inspection Scope

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

systems:

April 19, 2013, Unit 1, containment lower level for debris transport to the

containment sumps following the refueling outage

July 23, 2013, Unit 2, residual heat removal pump 2-01 when residual heat

removal pump 2-02 was unavailable for maintenance

September 10, 2013, the switchyard, Unit 2 diesel generators, and Units 1 and 2

turbine driven auxiliary feedwater pumps when transformer XST2 was

unavailable 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 focused on

discrepancies that could affect the function of the system, and, therefore, potentially

increase risk. The inspectors reviewed applicable operating procedures, system

diagrams, Final Safety Analysis Report, technical specification requirements,

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

walked down 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.

These activities constitute completion of three partial system walkdown samples as

defined in Inspection Procedure 71111.04-05.

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b. Findings

Introduction. The inspectors identified a Green non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to

follow instructions and remove cables from containment as part of a modification. As a

result, portions of 12 cables totaling approximately 100 feet in length wrapped with tape

on the ends remained in containment and could have been transported to the

emergency sumps during an accident.

Description. On April 19, 2013, the inspectors performed a walkdown of the Unit 1

containment to look for debris and other materials that could be transported to the

emergency sumps during an accident. The inspectors observed portions of cables with

cut ends wrapped in tape in the lower loop rooms. The inspectors informed the licensee

of the observation. The licensee determined that the cables should have been removed

as part of a design modification and that maintenance personnel did not follow the work

order instructions when removing the cables. The licensee initiated another work order

and removed the cables.

The inspectors determined, through discussion with licensee personnel, that the

personnel performing the maintenance activity did not involve supervision when they had

questions concerning the removal of the cables and proceeded in the face of uncertainty.

Analysis. The failure of the maintenance personnel to follow work order instructions and

remove materials from containment was a performance deficiency which resulted in

debris remaining in containment. The finding was more than minor because it was

associated with the equipment performance attribute of the mitigating systems

cornerstone and adversely affected the cornerstone objective to ensure the availability,

reliability, and capability of the emergency sumps. Using NRC Manual Chapter 0609,

Significance Determination Process, Appendix G, Shutdown Operations Significance

Determination Process, Attachment 1, Checklist 2, the finding was determined to be of

very low safety significance because the licensee maintained adequate mitigation

capability for the current plant state and the finding was not characterized as a loss of

control event. The finding has a human performance cross-cutting aspect associated

with work practices in that the maintenance personnel did not involve supervision when

they had questions concerning the removal of the cables and proceeded in the face of

uncertainty H.4(a).

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,

and Drawings, requires, in part, that activities affecting quality shall be prescribed by

documented instructions of a type appropriate to the circumstances and shall be

accomplished in accordance with these instructions. Work Order 4575654 implemented

a design change to remove cables from containment and Step 4, required, in part, to

remove the cable and insulating material from containment. Contrary to the above, on

April 10, 2013, maintenance personnel failed to follow documented instructions.

Specifically, the maintenance personnel failed to properly disconnect the cables and

remove them from containment. The licensee removed the materials before

returning the unit to service. Since the violation was of very low safety significance

and was documented in the licensees corrective action program as Condition

Report CR-2013-009443, it is being treated as a non-cited violation, consistent with

Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000445/2013004-01,

Failure to Remove Cable Material from Inside Containment.

-7-

1R05 Fire Protection (71111.05AQ)

.1 Quarterly Fire Inspection Tours (71111.05Q)

a. Inspection Scope

The inspectors conducted fire protection walkdowns in the following risk-significant plant

areas:

August 26, 2013, fire zone WB104a, service water intake structure

September 18, 2013, fire zone SD9, Unit 1 train A switchgear room

September 19, 2013, fire zone 2SD9, Unit 2 train A switchgear room

September 25, 2013, fire zone EC51, Unit 1 train B inverter room

September 25, 2013, fire zone EC50, Unit 2 train B inverter 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 or their

potential to affect equipment that could initiate or mitigate a plant transient. 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.

These activities constitute completion of five quarterly fire-protection inspection samples

as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation (71111.05A)

a. Inspection Scope

On September 10, 2013, the inspectors observed a fire brigade drill for a simulated fire

in Unit 2 centrifugal charging pump 2-02 room. The observation evaluated the readiness

of the plant fire brigade and control room staff to fight fires. The inspectors verified that

the licensee staff identified deficiencies; openly discussed them in a self-critical manner

at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated

were: (1) proper wearing of turnout gear and self-contained breathing apparatus;

(2) proper use and layout of fire hoses; (3) employment of appropriate firefighting

techniques; (4) sufficient firefighting equipment brought to the scene; (5) effectiveness of

fire brigade leader communications, command, and control; (6) search for victims and

propagation of the fire into other plant areas; (7) utilization of preplanned strategies; and

(8) adherence to the preplanned drill scenario.

-8-

These activities constitute completion of one annual fire protection drill observation

sample as defined by Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope

The inspectors reviewed the Final Safety Analysis Report, the flooding analysis, and

plant procedures to assess susceptibilities involving internal flooding; reviewed the

corrective action program to determine if licensee personnel identified and corrected

flooding problems; inspected spaces needing compensatory actions in order to protect

against internal flooding in cases where the circulating water system lake levels exceed

the 778 foot elevation; and verified that operator actions for coping with flooding can

reasonably achieve the desired outcomes. The inspectors also checked the floor and

wall penetration seals, watertight door seals, common drain lines and sumps, sump

pumps, level alarms, and control circuits that are integral to the internal flooding

mitigation strategy. The inspectors evaluated the following areas:

July 18, 2013, pathway from the circulating water discharge structure via

circulating water tunnels to turbine building and lower level of the electrical and

control building

July 18, 2013, recycle hold up tanks, laundry and hot shower tank, waste holdup

tank, and floor drain tanks in the auxiliary building

These activities constitute completion of two flood protection measures samples as

defined in Inspection Procedure 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

(71111.11)

.1 Quarterly Inspection of Licensed Operator Requalification Program (71111.11Q)

a. Inspection Scope

On August 12, 2013, the inspectors observed a crew of licensed operators in the plants

simulator during requalification training. The inspectors assessed the following areas:

Licensed operator performance

The ability of the licensee to administer the evaluations and training

The modeling and performance of the control room simulator

The quality of post-scenario critiques

Follow-up actions taken by the licensee for identified discrepancies

-9-

These activities constitute completion of one quarterly inspection of licensed operator

requalification program sample as defined in Inspection Procedure 71111.11-05.

b. Findings

No findings were identified.

.2 Quarterly Observation of Licensed Operator Performance (71111.11Q)

a. Inspection Scope

The inspectors observed the performance of on-shift licensed operators in the plants

main control room. At the time of the observations, the plant was in a period of

heightened activity. The inspectors assessed the operators adherence to plant

procedures and other operations department policies. The inspectors observed the

operators performance of the following activities:

July 8, 2013, Unit 1, reactivity management during the swapping from a

centrifugal charging pump to the positive displacement pump

July 27, 2013, Unit 1, down-power and manual reactor trip for planned

maintenance outage

These activities constitute completion of one quarterly observation of licensed-operator

performance sample as defined in Inspection Procedure 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors evaluated the following risk-significant systems, components, and

degraded performance issues:

Main steam safety valves

Unit 1, auxiliary feedwater system

The inspectors reviewed events where ineffective equipment maintenance had resulted

in failures and independently verified the licensee's actions to address system

performance or condition problems in terms of the following:

Implementing appropriate work practices

Identifying and addressing common cause failures

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

Characterizing system reliability issues for performance

Charging unavailability for performance

Trending key parameters for condition monitoring

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

- 10 -

The inspectors verified appropriate performance criteria for structures, systems, and

components classified as having an adequate demonstration of performance through

preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the

establishment of appropriate and adequate goals and corrective actions for systems

classified as not having adequate performance, as described in 10 CFR 50.65(a)(1).

The inspectors assessed performance issues with respect to the reliability, availability,

and condition monitoring of the system. In addition, the inspectors verified maintenance

effectiveness issues were entered into the corrective action program with the appropriate

significance characterization. Specific documents reviewed during this inspection are

listed in the attachment.

These activities constituted completion of two maintenance effectiveness samples as

defined in Inspection Procedure 71111.12-05.

b. Findings

Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50.65(a)(1)

for the licensees failure to establish performance goals and perform monitoring to

ensure the Unit 1 auxiliary feedwater system was capable of performing its intended

function.

Description. On August 29, 2013, the inspectors attended a maintenance rule review

panel meeting. As part of the meeting, a system engineer presented two events that

had caused the auxiliary feedwater system to exceed its performance criteria of two

functional failures in a two year period for the Unit 1 motor driven auxiliary feedwater

pumps. The first functional failure, associated with Condition Report CR-2012-011913,

documented air blowing from the motor driven auxiliary feedwater pump 1-01 to the

condensate recirculation flow valve regulator gauge, 1-FV-2456. The second functional

failure, associated with Condition Report CR-2012-013430, documented a failure of the

motor driven auxiliary feedwater pump 1-01 flow controller to steam generator 1-01,

1-FK-2453C, at the remote shutdown panel. The engineer presented to the panel an

approved and documented evaluation that concluded the cause was known and

eliminated and thus, monitoring against goals was unnecessary. The panel agreed with

the engineers presentation and voted to place the system in a maintenance rule (a)(2)

status.

The inspectors disagreed with the maintenance rule review panels determination of the

status of the Unit 1 auxiliary feedwater system. The inspectors informed the panel that

they had failed to consider a third functional failure of the system. The inspectors

described the functional failure, associated with Condition Report CR-2013-003358,

where air was blowing from the motor driven auxiliary feedwater pump 1-02 to the

condensate recirculation flow valve regulator gauge, 1-FV-2457. Based on the

inspectors comments, the maintenance rule review panel determined the Unit 1 auxiliary

feedwater system should remain in an (a)(1) status and goals need to be established.

The inspectors discussed the cause of the event with the licensee. The inspectors

determined that the licensee failed to obtain adequate interdisciplinary input when

determining the auxiliary feedwater maintenance rule status.

Analysis. The failure to establish goals and monitor the performance of the auxiliary

feedwater system was a performance deficiency. This finding was more than minor

because it was associated with the equipment performance attribute of the Mitigating

- 11 -

Systems cornerstone and adversely affected the cornerstone objective to ensure the

availability and reliability of systems that respond to initiating events to prevent

undesirable consequences. Using Inspection Manual Chapter 0609, Appendix A, The

Significance Determination Process for Findings At-Power, the finding was determined

to be of very low safety significance (Green) because the finding was not a design or

qualification deficiency; did not represent an actual loss of safety function of a system or

train; did not represent an actual loss of a technical specification train for greater than its

allowed outage time; and did not result in the loss of one or more trains of non-technical

specification trains of equipment. The finding had a human performance cross-cutting

aspect associated with decision-making, in that, the licensee failed to demonstrate that

nuclear safety is the overriding priority by not obtaining adequate interdisciplinary input

when determining the auxiliary feedwater maintenance rule status H.1(a).

Enforcement. Title 10 CFR 50.65(a)(1) requires, in part, that the licensee shall monitor

the performance or condition of structures, systems, or components within the scope of

the rule against licensee-established goals in a manner sufficient to provide reasonable

assurance that such structures, systems, or components are capable of fulfilling their

intended safety functions. Title 10 CFR 50.65(a)(2) requires, in part, that monitoring

specified in paragraph (a)(1) is not required where it has been demonstrated the

performance or condition of a system, structure, and component is being effectively

controlled through appropriate preventive maintenance, such that the structure, system,

or component remains capable of performing its intended function. Contrary to the

above, on February 28, 2013, the licensee failed to monitor the performance or condition

of structures, systems, or components within the scope of the rule against

licensee-established goals in a manner sufficient to provide reasonable assurance that

such structures, systems, or components are capable of fulfilling their intended safety

functions. Specifically, the licensee failed to demonstrate that the performance or

condition of the Unit 1 auxiliary feedwater system had been effectively controlled

through the performance of appropriate preventive maintenance and did not monitor the

system against licensee-established goals. Since the violation was of very low safety

significance and was documented in the licensees corrective action program as

Condition Report CR-2013-010024, it is being treated as a non-cited violation, consistent

with Section 2.3.2.a of the Enforcement Policy: NCV 05000445/2013004-02, Failure to

Establish Goals and Monitor the Performance of the Auxiliary Feedwater System.

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

a. Inspection Scope

The inspectors reviewed the licensees 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:

July 12, 2013, Unit 1, risk assessment associated with the planned unit outage to

repair the seal injection leak

July 25, 2013, Unit 2, service water pump 2-01 out of service for unplanned

corrective maintenance on the breaker secondary stab

July 30, 2013, Unit 2, component cooling water pump 2-02 out of service during

testing of service water pump 2-02

- 12 -

August 8, 2013, Unit 2, emergent switchyard work to repair a failed relay in the

345kV subsystem

September 10, 2013, Units 1 and 2, transformer XST2 out of service for planned

maintenance

September 18, 2013, Unit 1, diesel generator 1-02 out of service for planned

maintenance

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.

These activities constitute completion of six 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:

CR-2013-001446, Unit 1, inverter IV1PC4 board X40 solder connections

CR-2013-005376, Unit 1, void in residual heat removal piping

CR-2013-006795, Unit 1, increased reactor coolant system leak rate

CR-2013-008323, Unit 1, failure of diesel generator 1-01 starting air

compressor 1-01 relief valve

CR-2013-008552, Unit 2, leak from auxiliary feedwater to service water

cross-connect drain line

The inspectors selected these 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 Final Safety Analysis Report

- 13 -

to the licensees 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

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 five operability evaluation inspection samples

as defined in Inspection Procedure 71111.15-05.

b. Findings

Introduction. The inspectors reviewed a Green self-revealing finding for operations

personnel failure to follow instructions for the removal of the dissimilar metal elbow when

installing a pipe cap. As a result, the elbow eventually leaked, reactor coolant system

leakage increased, and a Unit 1 shutdown was needed to correct the issue.

Description. On June 27, 2013, the licensee observed that a 3/4 inch threaded

connection downstream of reactor coolant pump 1-02 seal injection line drain valve

1CS-8364B was leaking. The leak was coming from a threaded connection on a carbon

steel elbow that was threaded onto the stainless steel pipe nipple with a stainless steel

cap on the elbow. The correct setup for the components was a stainless cap on the

stainless steel nipple. The licensee determined the incorrect component configuration

occurred near the end of the refueling outage in April 2013.

The inspectors reviewed the licensees cause evaluation for the event. The inspectors

noted that Procedure OWI-404, Operations Vent and Drain Guidelines, Revision 8,

Step 6.4.1, in part, prohibits the use of dissimilar metals fittings inside containment. The

licensees evaluation indicated that operators understood the requirement. The

inspectors reviewed training records and concluded that the operators were trained on

the Procedure OWI-404 requirements.

The inspectors discussed the finding with the licensee and reviewed the cause analysis.

The inspectors determined that the component was in a hot, dark, and hard to reach

location, with interferences present. The poor environmental conditions were the likely

cause of the leaving the carbon steel elbow on the pipe.

Analysis. The failure of the operations personnel to follow instructions for the removal of

the dissimilar metal elbow when installing a pipe cap was a performance deficiency. As

a result, the elbow leaked and caused a unit shutdown. The finding was more than

minor because it was associated with the human performance attribute of the Initiating

Events cornerstone and adversely affected the cornerstone objective to limit the

likelihood of those events that upset plant stability and challenge critical safety functions

during shutdown as well as power operations. Using Inspection Manual Chapter 0609,

Appendix A, The Significance Determination Process for Findings At-Power, the finding

was determined to be of very low safety significance (Green) because the finding could

not result in exceeding the reactor coolant system leak rate for a small loss of coolant

accident and the finding would not have affected other systems used to mitigate a loss of

coolant accident resulting in a total loss of their function. The finding had a human

- 14 -

performance cross-cutting aspect associated with resources because the environmental

conditions impacted the ability of the operators to correctly install the pipe cap H.3(a).

Enforcement. This finding does not involve enforcement action because no violation of a

regulatory requirement was identified. The licensee documented the finding in the

corrective action program as Condition Report CR-2013-006795. Because the finding

does not involve a violation and is of very low safety significance, it is being

characterized as a finding FIN 05000445/2013004-03, Improper Pipe Cap Installation

Results in a Unit Shutdown.

1R18 Plant Modifications (71111.18)

a. Inspection Scope

The inspectors reviewed the plant modification associated with the plugging of the Unit 2

auxiliary condensers. The inspectors reviewed work instructions, and condition reports

associated with the modifications.

These activities constitute completion of one plant modification inspection sample as

defined in Inspection Procedure 71111.18-05.

b. Findings

Introduction. The inspectors reviewed a Green self-revealing finding for the licensees

failure to ensure the heat exchanger tube plugging procedure was adequate. As a

result, auxiliary condenser plugs were improperly inserted and caused a tube to leak.

This caused high sodium levels in the steam generators and a unit power reduction from

100 percent to less than 50 percent power.

Description. On November 6, 2012, with Unit 2 operating at 100 percent power, a

condenser tube leak occurred in the main feedwater pump auxiliary condenser 2A. This

failure caused the sodium levels in all four steam generators to rise. In accordance with

plant procedures, the licensee reduced power to less than 50 percent until the sodium

levels improved. The licensees root cause analysis concluded that the plugs were

improperly installed during the recent refueling outage in October, 2012, as a result of

inadequate procedure guidance. The instructions did not consider the thickness of the

auxiliary condenser and resulted in the plugs being inserted too far into the tube sheet

and damaging the actual tube. On November 9, 2012, the licensee identified two tubes

that were damaged by improper plug insertion depth. The licensee replaced a total of

42 plugs in the condensers.

The licensee had several opportunities to prevent incorrect installation of the tube plugs.

In May 2011, licensee personnel in a heat exchanger lab training session recognized

that tubes were damaged when the plugs were inserted the length specified in

Procedure MSM-G0-5870, Heat Exchanger Tube Plugging, Revision 0. Condition

Report CR-2011-006610 was initiated to document that Procedure MSM-G0-5870

needed to be changed to prevent inserting tubes too far in a condenser tube sheet and

causing tube distortion or tube breakage. The condition report was reviewed by the

station ownership committee and the management review committee and was closed

the following day based on the initiation of a procedure change submittal. The

procedure change submittal classified the change as a procedure enhancement. The

change was not completed prior to use on the auxiliary condenser.

- 15 -

During the plugging evolution, a vendor that performed a portion of the tube plugging

activities recognized that the procedure was incorrect in the insertion location of the

plug. The vendor marked up the procedure to annotate the correct location of the plug

and inserted the plug in the correct location. The corrected location was discussed in

the post-job debrief, but the procedure was not revised and a condition report was not

initiated. In addition, the licensee did not change the incorrect plugging of the condenser

that was performed by licensee maintenance personnel a few days earlier.

The inspectors determined that MSM-G0-5870, Heat Exchanger Tube Plugging,

Revision 0 was revised in 2005 when the auxiliary condensers were added to the

procedure. Procedure STA-202, Nuclear Generation Procedure Change Process,

Revision 31, Step 6.3.8, requires, in part, that a technical review be performed when

changing a procedure. The instructions in Procedure MSM-G0-5870 were not changed

to account for the differences in tubesheet thickness when the auxiliary condenser was

added to the procedure and therefore the plugs were inserted in the wrong location. The

inspectors concluded that the licensee failed to follow Procedure STA-202 and failed to

perform an adequate technical review of Procedure MSM-G0-5870.

The inspectors discussed the finding with the licensee and reviewed the licensees root

cause analysis. Although Procedure MSM-G0-5870 was revised to incorporate the

auxiliary condenser in 2005, the inspectors concluded that the finding is indicative of

current plant performance. The inspectors determined that within 18 months prior to the

event, the licensee had identified several instances where Procedure MSM-G0-5870

was inadequate and missed all of the opportunities to correct the procedure and install

the plugs in the correct location before returning the condenser to service.

Analysis. The licensees failure to ensure the heat exchanger tube plugging procedure

was adequate was a performance deficiency. As a result, an auxiliary condenser tube

failed causing a high sodium level in the steam generators and a unit power reduction.

The finding was more than minor because it was associated with the equipment

performance attribute of the Initiating Events cornerstone and adversely affected the

cornerstone objective, in that, it increased the likelihood of those events that upset plant

stability and challenge critical safety functions during power operations. Using

Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process

for Findings At-Power, the finding was determined to be of very low safety significance

(Green) because the finding did not cause a reactor trip and the loss of mitigation

equipment. The finding has a human performance cross-cutting aspect associated with

work practices in that licensee supervision failed to provide appropriate oversight to the

tube plugging procedure and plugging activity H.4(c).

Enforcement. This finding does not involve enforcement action because no violation of a

regulatory requirement was identified. The licensee documented the finding in the

corrective action program as Condition Report CR-2012-011805. Because the finding

does not involve a violation and is of very low safety significance, it is being

characterized as a finding FIN 05000446/2013004-04, Failure to Properly Install

Auxiliary Condenser Tube Plugs Causes Steam Generator Chemistry Excursion and

Unit Power Reduction.

- 16 -

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that

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

capability:

July 23, 2013, Unit 2, residual heat removal pump 2-02 testing following motor oil

change and breaker maintenance

August 26, 2013, Unit 2, reactor coolant pump under frequency relay testing

following under frequency relay replacement

September 12, 2013, Unit 1, turbine driven auxiliary feedwater pump

post-maintenance verification following governor valve stroke

September 18, 2013, Unit 1, diesel generator 1-02 testing following tachometer

and valve maintenance

September 19, 2013, Unit 2, motor driven auxiliary feedwater post-maintenance

testing following pressure gauge replacement.

September 20, 2013, Unit 1, containment spray pump 1-04 post-maintenance

testing following hand switch and light socket maintenance

The inspectors selected these activities based upon the structure, system, or

component's ability to affect risk. The inspectors evaluated these activities to ensure the

testing was adequate for the maintenance performed, the acceptance criteria were clear,

and the test ensured equipment operational readiness.

The inspectors evaluated the activities against technical specifications, the Final Safety

Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC

generic communications to ensure that the test results adequately ensured that the

equipment met the licensing basis and design requirements. In addition, the inspectors

reviewed corrective action documents associated with post-maintenance 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 six post-maintenance testing samples as

defined in Inspection Procedure 71111.19-05.

b. Findings

Introduction. The inspectors identified a Green non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to

follow procedures that require initiating a condition report for degradation to

safety-related equipment. During a surveillance activity, maintenance personnel

discovered that a reactor coolant pump under frequency relay was outside the as-found

setpoint tolerance for pick-up frequency and failed to enter the condition into the

- 17 -

corrective action program. As a result, the cause and effect of the degraded condition

was not evaluated and the relay again drifted outside the setpoint tolerance.

Description. On November 2, 2012, maintenance personnel performed a calibration of

under frequency relay 81/2A2 in accordance with Procedure MSE-S2-0665X, Unit 2

RCP Under Frequency Relay TADOT and Channel Calibration Surveillance, Revision 4.

The inspectors reviewed the work order that documented the as-found setpoint criteria

out of tolerance for the reactor coolant pump under frequency relay. The maintenance

personnel adjusted and retested the relay. The relay as-left frequency was within the

calibration limits. The inspectors verified that the work order documentation for the

surveillance test was complete and had been signed by a work supervisor and

operations shift management. The inspectors noted that none of the personnel involved

in the testing of the relay or the review of the work order package initiated a condition

report for the relay being outside the as-found setpoint criteria as required by Procedure

STA-421, Initiation of Condition Reports, Revision 18.

The inspectors determined, through discussion with licensee personnel, that the

personnel involved with the performance of the maintenance activity were not

adequately trained in the management expectation and procedure requirement to initiate

condition reports for as-found setpoints outside the tolerance band, a degraded

condition.

Analysis. The licensees failure to follow procedure and initiate a condition report for

degraded safety-related equipment was a performance deficiency. The finding was

more than minor because if the licensee continues to fail to document degraded

safety-related equipment in the corrective action database, there is a potential that this

could lead to a more significant safety concern, in that the cause of the degradation will

not be evaluated and corrected. Using Inspection Manual Chapter 0609, Appendix A,

The Significance Determination Process for Findings At-Power, the finding was

determined to be of very low safety significance (Green) because the finding was not a

design or qualification deficiency; did not represent an actual loss of safety function of a

system or train; did not represent an actual loss of a technical specification train for

greater than its allowed outage time; and did not result in the loss of one or more trains

of non-technical specification trains of equipment. The finding has a human

performance cross-cutting aspect associated with resources in that the licensee failed to

provide adequate training to personnel performing maintenance H.2(b).

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,

and Drawings, requires, in part, that activities affecting quality shall be prescribed by

documented instructions of a type appropriate to the circumstances and shall be

accomplished in accordance with these instructions. Procedure STA-421, Initiation of

Condition Reports, Revision 18, Attachment 8.A, Step 6.2 required, in part, that

equipment malfunctions, damage, or degradation, other than anticipated wear will be

documented in a condition report. Contrary to the above, on November 2, 2012, the

licensee performed an activity affecting quality and failed to accomplish the activity in

accordance with the instructions. Specifically, the licensee did not initiate a condition

report for an under frequency relay with an as-found setpoint outside the tolerance band.

Since the violation was of very low safety significance and was documented in the

licensees corrective action program as condition report CR-2013-010078, it is being

treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement

Policy: NCV 05000446/2013004-05, Failure to Initiate a Condition Report for a

Degraded Under Frequency Relay.

- 18 -

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors reviewed the Final Safety Analysis Report, procedure requirements,

technical specifications, and corrective action documents to ensure that the surveillance

activities listed below demonstrated that the systems, structures, and components tested

were capable of performing their intended safety functions.

Pump or Valve Inservice Test

July 30, 2013, Unit 2, service water pump 2-02 testing in accordance with

Procedure OPT-207B, Service Water System, Revision 14

Routine Surveillance Testing

August 6, 2013, Unit 1, residual heat removal and safety injection train A testing

in accordance with Procedure OPT-512A, RHR and SI Subsystem Valve Test,

Revision 10

September 5, 2013, Unit 2, steam generator 2-03 wide range level calibration in

accordance with Procedure INC-7412B, Channel Calibration Steam Generator 3

Wide Level, Protection Set II, Channel 0503, Revision 2

September 5, 2013, Unit 2, containment pressure calibration in accordance with

Procedure INC-7856B, Channel Operability Test and Channel Calibration

Containment Channel 0935, Protection Set III, Revision 5

September 11, 2013, Unit 2, diesel generator 2-01 testing in accordance with

Procedure OPT-214B, Diesel Generator Operability Test, Revision 16

September 18, 2013, off-site power sources verification in accordance with

Procedure OPT-215, Class 1E Electrical Systems Operability, Revision 15

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 and lifted lead controls

Test data

Testing frequency and method demonstrated technical specification operability

Test equipment removal

Restoration of plant systems

Fulfillment of ASME code requirements

Updating of performance indicator data

Reference setting data

Annunciators and alarms setpoints

- 19 -

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

These activities constitute completion of six surveillance testing inspection samples (one

pump or valve inservice test, and five routine surveillance testing samples) as defined in

Inspection Procedure 71111.22-05.

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope

On July 31, 2013, the inspectors evaluated the conduct of licensee emergency drills to

identify any weaknesses and deficiencies in classification, notification, and protective

action recommendation development activities. The inspectors observed emergency

response operations in the simulator and the emergency operations facility to determine

whether the event classification, notifications, and protective action recommendations

were performed in accordance with procedures. The inspectors also compared any

inspector-observed weakness with those identified by the licensee staff in order to

evaluate the critique and to verify whether the licensee staff was properly identifying

weaknesses and entering them into the corrective action program.

These activities constituted completion of one drill and/or training evolution sample as

defined in Inspection Procedure 71114.06-06.

b. Findings

No findings were identified.

4. OTHER ACTIVITIES

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

Preparedness, Public Radiation Safety, and Occupational Radiation Safety

4OA1 Performance Indicator Verification (71151)

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the second

quarter 2013 performance indicators for any obvious inconsistencies prior to its public

release in accordance with NRC 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.

- 20 -

b. Findings

No findings were identified.

.2 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system specific

activity performance indicator for Units 1 and 2 for the period from the second

quarter 2012 through the first quarter 2013. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

definitions and guidance contained in Nuclear Energy Institute Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The

inspectors reviewed the licensees reactor coolant system chemistry samples, technical

specification requirements, condition reports, and NRC integrated inspection reports to

validate the accuracy of the submittals. The inspectors also reviewed the licensees

condition 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.

These activities constitute completion of two reactor coolant system specific activity

samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Reactor Coolant System Leakage (BI02)

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system leakage

performance indicator for Units 1 and 2 for the period from the second quarter 2012

through the first quarter 2013. To determine the accuracy of the performance indicator

data reported during those periods, performance indicator definitions and guidance

contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the

licensees operator logs, reactor coolant system leakage tracking data, condition reports,

and NRC integrated inspection reports to validate the accuracy of the submittals. The

inspectors also reviewed the licensees condition report database to determine if any

problems had been identified with the performance indicator data collected or

transmitted for this indicator.

These activities constitute completion of two reactor coolant system leakage samples as

defined by Inspection Procedure 71151-05.

b. Findings

No findings were identified.

- 21 -

.4 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 third quarter 2012 through the second quarter 2013. To determine the accuracy

of the performance indicator data reported during those periods, the inspectors used

definitions and guidance contained in Nuclear Energy Institute Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors

reviewed the licensees operator narrative logs, mitigating systems performance index

derivation reports, condition reports, and NRC integrated inspection reports 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 Nuclear Energy Institute guidance. The inspectors also

reviewed the licensees condition 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.

These activities constitute completion of two mitigating systems performance index

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

b. Findings

No findings were identified.

.5 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 third quarter 2012 through the second quarter 2013. To determine the

accuracy of the performance indicator data reported during those periods, the inspectors

used definitions and guidance contained in Nuclear Energy Institute Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors

reviewed the licensees operator narrative logs, condition reports, mitigating systems

performance index derivation reports, and NRC integrated inspection reports 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 Nuclear Energy Institute guidance. The inspectors also

reviewed the licensees condition 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.

These activities constitute completion of two mitigating systems performance index high

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

- 22 -

b. Findings

No findings were identified.

.6 Mitigating Systems Performance Index - Heat Removal System (MS08)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance

index heat removal system performance indicator for Units 1 and 2 for the period from

the third quarter 2012 through the second quarter 2013. To determine the accuracy of

the performance indicator data reported during those periods, the inspectors used