ML063130383

IR 05000482-06-004; Wolf Creek Nuclear Operating Corporation; 07/08/06 - 10/7/06; Wolf Creek Generating Station; Operability Evaluations, Identification and Resolution of Problems, and Event Follow-up

ML063130383
Person / Time
Site:	Wolf Creek
Issue date:	11/09/2006
From:	Geoffrey Miller NRC/RGN-IV/DRP/RPB-B
To:	Muench R Wolf Creek
References
IR-06-004
Download: ML063130383 (37)

See also: IR 05000482/2006004

Text

November 9, 2006

Rick A. Muench, President and

Chief Executive Officer

Wolf Creek Nuclear Operating Corporation

P.O. Box 411

Burlington, KS 66839

SUBJECT: WOLF CREEK GENERATING STATION - NRC INTEGRATED INSPECTION

REPORT 05000482/2006004

Dear Mr. Muench:

On October 7, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection

at your Wolf Creek Generating Station. The enclosed integrated report documents the

inspection findings which were discussed on October 6, 2006, with Mr. S. E. Hedges, Vice

President Operations and Plant Manager, and other members of your staff.

This inspection 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.

Within these areas, the inspection consisted of selected examination of procedures and

representative records, observation of activities, and interviews with personnel.

This report documents one NRC-identified finding and two self-revealing findings of very low

safety significance (Green). All of these findings were determined to involve violations of NRC

requirements. Additionally, two licensee-identified violations which were determined to be of

very low safety significance (Green), are listed in Section 4OA7 of this report. The NRC is

treating these violations as noncited violations consistent with Section VI.A.1 of the NRC

Enforcement Policy because of the very low safety significance and because the findings were

entered into your corrective action program. If you contest these noncited violations or the

significance of these noncited violations, you should provide a response within 30 days 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, U.S. Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Dr, Suite 400,

Arlington, Texas 76011; the Director, Office of Enforcement, U.S. Nuclear Regulatory

Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Wolf Creek

Generating Station.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its

enclosure, your response (if any) will be made available electronically for public inspection in

the NRC Public Document Room or from the Publicly Available Records component of NRCs

document system (ADAMS). ADAMS is accessible from the NRC Web site at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Wolf Creek Nuclear Operating Corporation -2-

Should you have any questions concerning this inspection, we will be pleased to discuss them

with you.

Sincerely,

/RA/

Geoffrey B. Miller, Chief

Project Branch B

Division of Reactor Projects

Docket: 50-482

License: NPF-42

Enclosure:

NRC Inspection Report 05000482/2006004

w/attachment: Supplemental Information

cc w/enclosure:

Vice President Operations/Plant Manager

Wolf Creek Nuclear Operating Corp.

P.O. Box 411

Burlington, KS 66839

Jay Silberg, Esq.

Pillsbury Winthrop Shaw Pittman LLP

2300 N Street, NW

Washington, DC 20037

Supervisor Licensing

Wolf Creek Nuclear Operating Corp.

P.O. Box 411

Burlington, KS 66839

Chief Engineer

Utilities Division

Kansas Corporation Commission

1500 SW Arrowhead Road

Topeka, KS 66604-4027

Office of the Governor

State of Kansas

Topeka, KS 66612

Wolf Creek Nuclear Operating Corporation -3-

Attorney General

120 S.W. 10th Avenue, 2nd Floor

Topeka, KS 66612-1597

County Clerk

Coffey County Courthouse

110 South 6th Street

Burlington, KS 66839-1798

Chief, Radiation and Asbestos

Control Section

Kansas Department of Health and

Environment

Bureau of Air and Radiation

1000 SW Jackson, Suite 310

Topeka, KS 66612-1366

Chief, Radiological Emergency

Preparedness Section

Kansas City Field Office

Chemical and Nuclear Preparedness

and Protection Division

Dept. of Homeland Security

9221 Ward Parkway

Suite 300

Kansas City, MO 64114-3372

Wolf Creek Nuclear Operating Corporation -4-

Electronic distribution by RIV:

Regional Administrator (BSM1)

DRP Director (ATH)

DRS Director (DDC)

DRS Deputy Director (RJC1)

Senior Resident Inspector (SDC)

SRI, Callaway (MSP)

Branch Chief, DRP/B (GBM)

Senior Project Engineer, DRP/B (FLB2)

Team Leader, DRP/TSS (RVA)

RITS Coordinator (KEG)

DRS STA (DAP)

J. Lamb, OEDO RIV Coordinator (JGL1)

ROPreports

WC Site Secretary (SLA2)

W. A. Maier, RSLO (WAM)

R. E. Kahler, NSIR (REK)

SUNSI Review Completed: __gbm___ ADAMS: : Yes G No Initials: __gbm__

Publicly Available G Non-Publicly Available G Sensitive  : Non-Sensitive

R:\_REACTORS\_WC\2006\WC2006-04RP-SDC.wpd

SRI:DRP/B RI:DRP/B SRA:DRS C:DRS/OB C:DRS/PSB

SDCochrum:sa JRGroom RLBywater RLNease MPShannon

E - GBMiller E - GBMiller /RA/ /RA/ /RA/

11/9/06 11/8/06 11/3/06 11/2/06 11/3/06

C:DRS/EB2 C:DRS/EB1 C:DRP/B

LJSmith JAClark GBMiller

/RA/ /RA/ /RA/

11/7/06 11/3/06 11/9/06

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

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 50-482

License: NPF-42

Report: 05000482/2006004

Licensee: Wolf Creek Nuclear Operating Corporation

Facility: Wolf Creek Generating Station

Location: 1550 Oxen Lane NE

Burlington, Kansas

Dates: July 8 through October 7, 2006

Inspectors: S. D. Cochrum, Senior Resident Inspector

T. B. Rhoades, Resident Inspector

J. R. Groom, Resident Inspector

P. J. Elkmann, Emergency Preparedness Inspector

M. E. Murphy, Senior Operations Engineer

Approved By: G. B. Miller, Chief, Project Branch B

-1- Enclosure

TABLE OF CONTENTS

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R07 Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

1R11 Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

1R13 Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 12

1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1R19 Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1EP4 Emergency Action Level and Emergency Plan Changes . . . . . . . . . . . . . . . . . 19

1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

4OA3 Follow-up of Events and Notices of Enforcement Discretion . . . . . . . . . . . . . . 23

4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

LIST OF ITEMS OPENED AND CLOSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-5

-2- Enclosure

SUMMARY OF FINDINGS

IR 05000482/2006004; 07/08/06 - 10/7/06; Wolf Creek Generating Station; Operability

Evaluations, Identification and Resolution of Problems, and Event Follow-up.

This report covered a 3-month inspection by resident and health physics inspectors. The

inspection identified three Green findings, all of which were noncited violations. The

significance of most findings is indicated by their color (Green, White, Yellow, or Red) using

Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the

significance determination process does not apply may be Green or be assigned a severity

level after NRC management review. The NRCs program for overseeing the safe operation of

commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process,"

Revision 3, dated July 2000.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

• Green. The inspectors reviewed a self-revealing noncited violation of Technical

Specification 5.4.1.a involving the licensee's failure to follow a procedure that

resulted in a loss of coolant charging flow during a planned surveillance. The

licensee entered this issue into their corrective action program as Condition

Report 2006-0002030.

The failure to follow station procedures was considered a performance

deficiency. This finding was more than minor because it affected the human

performance attribute of the initiating events cornerstone and the cornerstone

objective to limit the likelihood of those events that upset plant stability and

challenge critical safety functions. Using Manual Chapter 0609, Significance

Determination Process, Phase 1 worksheets, this finding screened to a Phase 2

analysis because it affected both the initiating events and mitigating system

cornerstones. The inspectors performed a Phase 2 analysis using Appendix A,

"Technical Basis For At Power Significance Determination Process," of Manual

Chapter 0609, "Significance Determination Process," and the Phase 2

worksheets for the Wolf Creek Generating Station. Based on the results of the

Phase 2 analysis, the finding is determined to have very low safety significance.

The inspectors also determined that the finding has crosscutting aspects in the

area of human performance associated with work practices because the

operators failure to use appropriate human error prevention techniques, such as

self-checking, peer-checking, and the operators choice to proceed in the face of

uncertainty, resulted in a loss of coolant charging flow (Section 4OA3).

-3- Enclosure

Cornerstone: Mitigating Systems

• Green. The inspectors identified a noncited violation of 10 CFR Part 50,

Appendix B, Criterion V, regarding the failure to implement administrative

Procedure AP 28-011, Resolving Deficiencies Impacting SSCs, Revision 1.

Procedure AP 28-011 requires that, during the operability determination process,

a reasonable expectation must exist that the structure, system, or component is

operable and that the prompt determination process will support that expectation.

Contrary to this requirement, reasonable expectation was not established for a

deficiency affecting safety-related Barton pressure transmitters. The licensee

entered this issue into their corrective action program as Condition Report 2006-

000895.

The failure to implement Procedure AP 28-011 following identification of a

potential degraded condition was a performance deficiency. This finding was

more than minor because it affected the equipment performance attribute of the

mitigating systems cornerstone and the cornerstone objective to ensure the

availability, reliability, and capability of systems that respond to initiating events.

Using Manual Chapter 0609, Significance Determination Process, Phase 1

worksheets, the inspectors determined that the finding is of very low significance

because it did not represent a loss of a safety function or operability and was not

potentially risk significant due to external events. The inspectors also

determined that this finding has crosscutting aspects in the human performance

area associated with decision making in that the licensee failed to use

conservative assumptions in decision making and verify the validity of underlying

assumptions for operability of the pressure transmitters, which resulted in

indeterminate pressure transmitters remaining in service (Section 1R15).

Cornerstone: Barrier Integrity

• Green. A self-revealing noncited violation of Technical Specification 5.4.1.a was

identified for the failure to close Valves EC-V025 and -V033 during a lineup to

recirculate the refueling water storage tank through the spent fuel pool cleanup

system. These two systems were cross-connected for approximately 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br />,

which resulted in approximately 1200 gallons of spent fuel pool water being

inadvertently transferred to the refueling water storage tank. The licensee

entered this issue into their corrective action program as Condition Report 2006-

000589.

The failure to completely close Valves EC-V025 and -V033 was a performance

deficiency. This finding is more than minor because it is associated with the

barrier integrity cornerstone attribute of configuration control and affected the

cornerstone objective to maintain functionality of the spent fuel pool system.

Using Manual Chapter 0609, Significance Determination Process, Phase 1

worksheets, the inspectors determined that the finding is only of very low

significance because the finding only affected the barrier function of the spent

fuel pool. The inspectors also determined that the finding has crosscutting

aspects in the area of human performance associated with work practices

-4- Enclosure

because the operators failed to use appropriate human error prevention

techniques, such as peer-checking and not proceeding in the face of uncertainty.

This led to 1200 gallons of spent fuel pool water being inadvertently transferred

to the refueling water storage tank (Section 4OA2.2)

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 actions are listed in Section 4OA7 of this report.

-5- Enclosure

REPORT DETAILS

Summary of Plant Status

The plant started the inspection period at 100 percent rated thermal power. On September 24,

2006, the licensee reduced reactor power to 97 percent to replace a seal on heater drain

Pump B for planned maintenance. After completion of maintenance on September 29, 2006,

the reactor was returned to 100 percent power. On October 1, 2006, the licensee reduced

reactor power to 97 percent to replace a seal on heater drain Pump A for planned maintenance.

After completion of maintenance on October 4, 2006, the reactor was returned to 100 percent

power and remained at or near this power level until October 7, 2006, when the Wolf Creek

Generating Station main output breakers were opened to begin Refueling Outage 15.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

Readiness for Seasonal Susceptibilities

a. Inspection Scope

The inspectors completed a review of the licensee's readiness of seasonal

susceptibilities involving high outdoor temperatures. The inspectors: (1) reviewed plant

procedures, the Updated Safety Analysis Report (USAR), and Technical

Specifications (TS) to ensure that operator actions defined in adverse weather

procedures maintained the readiness of essential systems; (2) walked down portions of

affected systems to ensure that adverse weather protection features were sufficient to

support operability, including the ability to perform safe shutdown functions;

(3) evaluated operator staffing levels to ensure the licensee would maintain the

readiness of essential systems required by plant procedures; and (4) reviewed the CAP

to determine if the licensee identified and corrected problems related to adverse

weather conditions.

C July 19, 2006, verification of the licensees preparations for impending high

outdoor temperatures and response to increasing cooling lake temperatures.

Documents reviewed by the inspectors included:

• Procedure GEN HW-001, Hot Weather Operation, Revision 2

• Procedure C-KC303, ESWS Pumphouse Concrete Neat Line Plan at EL 2000,

Revision 17

• Procedure SYS EF-205, ESW/CIRC Water Cold Weather Operations,

Revision 17

• Procedure STN EF-020A, ESW Train A Warming Line Verification, Revision 3

-6- Enclosure

• Procedure J-K4EF99, Non-Process Connected and In Line Electrical

Instruments, Revision 4

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

Partial System Walkdowns

a. Inspection Scope

The inspectors: (1) walked down portions of the risk important systems listed below and

reviewed plant procedures and documents to verify that critical portions of the selected

systems were correctly aligned; and (2) compared deficiencies identified during the

walkdown to the licensee's USAR and CAP to ensure problems were being identified

and corrected.

C July 27, 2006, Train A residual heat removal during a Train B residual heat

removal outage

C August 15, 2006, Train A essential service water during a Train B essential

service water outage

Documents reviewed by the inspectors included:

• Checklist CKL EJ-120, RHR Normal System Lineup, Revision 34

• Drawing M-13EJ01, Piping Isometric Residual Heat Removal System Auxiliary

Bldg Train A, Revision 13

• Checklist CKL EF-120, Essential Service Water Valve, Breaker and Switch

Lineup, Revision 40

• Drawing SK-M-13EF06, Piping Isometric Essential Service Water SYS. Aux.

BLD. A & B Train Supply and Return, Revision E

• Drawing M-13EF02, Piping Isometric Essential Service Water SYS Aux. Bldg. A

Train Supply, Revision 9

• Wolf Creek Generating Station USAR, Revision 19

The inspectors completed two samples.

-7- Enclosure

b. Findings

No findings of significance were identified

1R05 Fire Protection (71111.05)

.1 Quarterly Inspection

a. Inspection Scope

The inspectors walked down the plant areas listed below to assess the material

condition of active and passive fire protection features and their operational lineup and

readiness. The inspectors: (1) verified that transient combustibles and hot work

activities were controlled in accordance with plant procedures; (2) observed the

condition of fire detection devices to verify they remained functional; (3) observed fire

suppression systems to verify they remained functional; (4) verified that fire

extinguishers and hose stations were provided at their designated locations and that

they were in a satisfactory condition; (5) verified that passive fire protection features

(electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration

seals, and oil collection systems) were in a satisfactory material condition; (6) verified

that adequate compensatory measures were established for degraded or inoperable fire

protection features and that the compensatory measures were commensurate with the

significance of the deficiency; and (7) reviewed the CAP to determine if the licensee

identified and corrected fire protection problems.

• July 26, 2006, boron thermal regeneration system letdown heat exchanger room,

1976 level of the auxiliary building

• July 26, 2006, boric acid tank Rooms A and B, 1976 level of auxiliary building

• July 27, 2006, Train B residual heat removal heat exchanger room

• July 27, 2006, pipe chase room, 1988 level of the auxiliary building

• August 16, 2006, control building, 2073 level

• September 29, 2006, turbine building, 2033 level

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

-8- Enclosure

.2 Annual Inspection

a. Inspection Scope

On July 24, 2006, the inspectors observed a fire brigade drill to evaluate the readiness

of licensee personnel to prevent and fight fires, including the following aspects: (1) the

number of personnel assigned to the fire brigade, (2) use of protective clothing, (3) use

of breathing apparatuses, (4) use of fire procedures and declarations of emergency

action levels, (5) command of the fire brigade, (6) implementation of prefire strategies

and briefs, (7) access routes to the fire and the timeliness of the fire brigade response,

(8) establishment of communications, (9) effectiveness of radio communications,

(10) placement and use of fire hoses, (11) entry into the fire area, (12) use of firefighting

equipment, (13) searches for fire victims and fire propagation, (14) smoke removal,

(15) use of prefire plans, (16) adherence to the drill scenario, (17) performance of the

evaluators critique, and (18) restoration from the fire drill. The licensee simulated a fire

in the station service transformer.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

The inspectors reviewed Wolf Creek programs, verified performance tests against

industry standards, and reviewed critical operating parameters and maintenance records

for the containment heat exchangers. The inspectors verified that: (1) performance

tests were satisfactorily conducted for the heat exchangers and reviewed for problems

or errors; (2) Wolf Creek utilized the periodic maintenance method outlined in Electric

Power Research Institute NP-7552, Heat Exchanger Performance Monitoring

Guidelines; and (3) the containment cooling system was correctly categorized under the

maintenance rule.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

-9- Enclosure

1R11 Licensed Operator Requalification Program (71111.11)

.1 Biennial Review

a. Inspection Scope

This inspection was held during the 2006 biennial examination testing cycle. The

inspectors reviewed the overall pass/fail results of the individual job performance

measure operating tests, simulator operating tests, and written examinations

administered by the licensee during the operator licensing requalification cycles and

biennial examination. Eighteen crews participated in simulator operating tests, and job

performance measure operating tests, totaling 49 licensed operators.

During the inspection, the NRC inspectors reviewed and observed biennial examination

simulator job performance measures, in-plant job performance measures, the simulator

static examination, written examination, licensed operator classroom instruction, and the

plant control room crew. They also reviewed a sample of licensed operator annual

medical forms and procedures governing the medical examination process.

The inspectors assessed the methods and effectiveness of the licensees processes

for revising and maintaining its licensed operator requalification training program up to

date, including the use of feedback from plant events and industry experience

information. The inspectors reviewed the licensees training review group activities,

including the licensees ability to assess the effectiveness of its licensed operator

requalification training program and their ability to implement appropriate corrective

actions. This evaluation was performed to verify compliance with 10 CFR 55.59c,

"Requalification Program Requirements," and the licensees site access training

program.

The inspectors also assessed the adequacy and effectiveness of the remedial training

conducted since the previous biennial requalification examinations and the training from

the current examination cycle to ensure that they addressed weaknesses in licensed

operator or crew performance identified during training and plant operations. The

inspectors reviewed remedial training procedures and individual remedial training plans.

This evaluation was performed in accordance with 10 CFR 55.59c, "Requalification

Program Requirements," and with respect to the licensees site access training

program.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

-10- Enclosure

.2 Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors observed testing and training of senior reactor operators and reactor

operators to identify deficiencies and discrepancies in the training, to assess operator

performance, and to assess the evaluator's critique during the training scenarios listed

below.

• June 2, 2006, loss of shutdown cooling

• August 30, 2006, steam generator tube rupture with a loss of instrument air

Documents reviewed by the inspectors included:

• Simulator Scenario LR5004003 006, loss of RHR

Simulator Scenario LR5004010 000, intersystem LOCA

• Operations Requalification Cycle 06-05 schedule, Revision 000

• Procedure AP 15C-002, Procedure Use and Adherence, Revision 22

• Procedure AP 21-001, Conduct of Operations, Revision 36

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors reviewed the maintenance activities listed below to: (1) verify the

appropriate handling of structure, system, and component (SSC) performance or

condition problems; (2) verify the appropriate handling of degraded SSC functional

performance; (3) evaluate the role of work practices and common cause problems; and

(4) evaluate the handling of SSC issues reviewed under the requirements of the

maintenance rule, 10 CFR Part 50, Appendix B, and the TSs.

• August 2, 2006, Tcold wide-range temperature instrument, Work Order 06-056523

• August 11, 2006, stator cooling water system, Function CE-01

Documents reviewed by the inspectors included:

• Engineering Desktop Instruction EDI 23M-050, Monitoring Performance to

Criteria and Goals, Revision 3

-11- Enclosure

• PIR 2005-2152

• Work Order 06-056523

• Work Request 6056161

• Work Request 4044511

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

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

a. Inspection Scope

Risk Assessment and Management of Risk

The inspectors reviewed the assessment activities listed below to verify:

(1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and

licensee procedures prior to changes in plant configuration for maintenance activities

and plant operations; (2) the accuracy, adequacy, and completeness of the information

considered in the risk assessment; (3) that the licensee recognizes, and/or enters as

applicable, the appropriate licensee-established risk category according to the risk

assessment results and licensee procedures; and (4) that the licensee identified and

corrected problems related to maintenance risk assessments.

• August 14-19, 2006, Train B essential service water outage and Train B

emergency diesel generator outage

• September 5-8, 2006, Train A residual heat removal pump and Train A coolant

charging pump outage

Documents reviewed by the inspectors are listed in the attachment.

Emergent Work Control

The inspectors: (1) verified that the licensee performed actions to minimize the

probability of initiating events and maintained the functional capability of mitigating

systems and barrier integrity systems; (2) verified that emergent work-related activities

such as troubleshooting, work planning/scheduling, establishing plant conditions,

aligning equipment, tagging, temporary modifications, and equipment restoration did not

place the plant in an unacceptable configuration; and (3) reviewed the USAR and CAP

to determine if the licensee identified and corrected risk assessment and emergent work

control problems.

-12- Enclosure

• August 6, 2006, emergent work on instrument air dryer, Work Order 06-056595

• August 7, 2006, opening main generator output Breakers 345-50 and 345-60 for

Transformer SF-6 gas addition

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors: (1) reviewed plant status documents, such as operator shift logs,

emergent work documentation, deferred modifications, and standing orders, to

determine if an operability evaluation was warranted for degraded components;

(2) referred to the USAR and design basis documents to review the technical adequacy

of licensee operability evaluations; (3) evaluated compensatory measures associated

with operability evaluations; (4) determined degraded component impact on any TSs;

(5) used the significance determination process to evaluate the risk significance of

degraded or inoperable equipment; and (6) verified that the licensee has identified and

implemented appropriate corrective actions associated with degraded components.

• May 27, 2006, Barton Model 763 and 763A gage pressure transmitters

• August 1, 2006, Class 1E electrical equipment air conditioning Unit A (SGK05A)

unloader

• August 17, 2006, emergency diesel Generator B jacket water leak

Documents reviewed by the inspectors included:

• Condition Report 2006-000895

• Industry Technical Information Program 02005

• Operability Evaluation XX-06-003

• Procedure AP 26C-004, Technical Specification Operability, Revision 14

• Procedure AP 28-001, Operability Evaluations, Revision 14

• Work Request 00077-93

The inspectors completed three samples.

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b. Findings

Introduction: The inspectors identified a Green noncited violation (NCV) of 10 CFR

Part 50, Appendix B, Criterion V, regarding the failure to implement Administrative

Procedure AP 28-011, Resolving Deficiencies Impacting SSCs, Revision 1.

Description: On June 27, 2006, the inspectors identified an inadequate evaluation of a

deficiency impacting the operability of several safety-related pressure transmitters.

On May 18, 2006, PRIME Measurement Products issued a Nuclear Industry Advisory

that Barton Model 763 and 763A gage pressure transmitters and Model 764 differential

pressure transmitters may have defective external lead-wire connectors. The advisory

described a defect where the insulated portions of the wires in the connectors may not

be embedded deeply enough into the epoxy potting used to structurally support the

soldered wire connections and establish a seal to protect the solder connections from

shorting. The advisory warned that shorting of conductors could occur in an electrically

conductive accident environment. The advisory stated the affected transmitters were

manufactured after May 1982 and shipped from the factory prior to April 1, 2006.

Transmitters manufactured prior to June 1982 and assembled with heat shrinking

embedded in the epoxy potting were not subject to the concerns of the PRIME advisory.

PRIME recommended that all connectors in transmitters manufactured after May 1982

be inspected for exposure of the external lead wire conductors at the surface of the

connector and that any transmitter with exposed conductors should be considered

defective and replaced. Because of the design and configuration of the transmitters, the

inspections would necessitate the connector be unscrewed from the transmitter and the

external lead wires flexed 90 degrees to ensure the insulated portions of the wires are

securely embedded in the epoxy potting material. On June 21, 2006, following

inspection of warehouse stock potentially affected by the PRIME advisory, Callaway

plant made a 10 CFR Part 21 report notifying the NRC of defects in Barton pressure

transmitters.

Based on preliminary information from Callaway Plant, Wolf Creek Generating Station

initiated Condition Report 2006-000895 on June 19, 2006, to assess the applicability of

the 10 CFR Part 21 report. The licensee determined that the affected Barton models

were used onsite with a total of 39 safety-related transmitters installed. Significant

functions supported by the affected transmitters were main steam pressure indication

and trip functions, steam generator level indiction and trip functions, pressurizer level

indication and trip functions, and reactor coolant system wide-range pressure

indications. System engineering performed an operability evaluation to assess if any of

the installed transmitters were defective. As part of the operability justification basis,

system engineering referred to previous inspections performed by instrumentation and

control technicians under Work Request 00077-93. These inspections were performed

in 1993 and were in response to Westinghouse Letter SAP-92-182 that identified the

potential for damage to lead wire insulation on Barton pressure transmitters. The letter

identified a potential defect caused by lead wire rubbing against the internal threads of

the housing boss, resulting in insulation damage. Westinghouse recommended that

each transmitter be inspected for wire insulation damage; however, this only required

inspection at the entrance to the transmitter housing. Work Request 00077-93

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contained steps to inspect the transmitters addressed in the Westinghouse letter, which

included removing the conduit flex cable and conduit connector and inspecting the

transmitter lead wire at point of exit from the transmitter housing. The inspection criteria

established in the work order only required that the wire insulation be smooth,

unblemished, and free of nicks. Specifically, the work order did not contain the

requirements to unscrew the connector from the transmitter and that the external lead

wires be flexed 90 degrees to ensure the insulated portions of the wires are securely

embedded in the epoxy potting material as recommended in the current PRIME

advisory.

The licensee performed inspections on June 27, 2006, of two Barton pressure

transmitters affected by the PRIME advisory that were not included in the scope of the

1993 inspections. The resident inspector observed the inspections of these two

transmitters. In both cases, the inspection revealed that the transmitters were

assembled with heat shrinking embedded in the epoxy potting and, therefore, not

subject to the advisory. However, the inspectors questioned how the 1993 inspections

could identify the defective condition. Specifically, the inspectors questioned how the

previous inspections could take credit to identify the insulated portions of the wires were

securely embedded in the epoxy potting material, since the connectors were not

unscrewed from the transmitter and the external lead wires were not flexed 90 degrees.

Additionally, the inspectors noted that the lead wires and epoxy potting are inaccessible

without removal of the connector; therefore, the recommended inspection could not be

completed.

A review of the inspections performed in 1993 revealed 14 Barton pressure transmitters

manufactured without heat shrinking embedded in the epoxy potting and, therefore,

potentially affected by the PRIME advisory. The licensee inspected several spare lead

wire assemblies in stock and found one with a defect in the epoxy, but has not inspected

spare and installed Barton pressure transmitters.

Procedure AP 28-011 requires that, during the operability determination process, a

reasonable expectation must exist that the SSC is operable and that the prompt

determination process will support that expectation. Contrary to this requirement,

reasonable expectation was not established because the 1993 inspections did not

support the engineering judgement used. The licensee failed to inspect installed Barton

pressure transmitters and identify transmitters with known potential manufacturing

defects. In response to this finding, the licensee has developed an accelerated

schedule for inspection of the potentially affected transmitters as part of Condition

Report 2006-000895.

Analysis: The failure to implement Procedure AP 28-011 following identification of a

potential degraded condition was a performance deficiency. This finding was more than

minor because it affected the equipment performance attribute of the mitigating systems

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

capability of systems that respond to initiating events. Using Manual Chapter 0609,

Significance Determination Process, Phase 1 worksheets, the inspectors determined

that the finding is of very low significance because it did not represent a loss of a safety

function or operability and was not potentially risk significant due to external events.

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The inspectors also determined that this finding has crosscutting aspects in the human

performance area associated with decision making in that the licensee failed to use

conservative assumptions in decision making and verify the validity of underlying

assumptions for operability of the pressure transmitters.

Enforcement: 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and

Drawings," states, in part, that activities affecting quality shall be prescribed by

documented instructions, procedures, or drawings, of a type appropriate to the

circumstances and shall be accomplished in accordance with these instructions,

procedures, or drawings." Administrative Procedure AP28-011, Resolving Deficiencies

Impacting SSCs, Revision 1, step 6.4, requires the licensee to document a basis for

reasonable assurance of operability based on analysis, test, experience, or judgement

or declare the system inoperable. Contrary to this, the licensee failed to document a

reasonable assurance or declare affected equipment inoperable in the absence of a

reasonable assurance of operability. Because the violation was of very low safety

significance and has been entered into the licensees CAP as Condition Report 2006-

000895, this violation is being treated as an NCV, consistent with Section VI.A of the

Enforcement Policy: NCV 05000482/2006004-01, Inadequate inspections of potentially

defective pressure transmitters.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors selected the below listed postmaintenance test activities of risk

significant systems or components. For each item, the inspectors: (1) reviewed the

applicable licensing basis and/or design-basis documents to determine the safety

functions; (2) evaluated the safety functions that may have been affected by the

maintenance activity; and (3) reviewed the test procedure to ensure it adequately tested

the safety function that may have been affected. The inspectors either witnessed or

reviewed test data to verify that acceptance criteria were met, plant impacts were

evaluated, test equipment was calibrated, procedures were followed, jumpers were

properly controlled, the test data results were complete and accurate, the test

equipment was removed, the system was properly realigned, and deficiencies during

testing were documented. The inspectors also reviewed the USAR and CAP to

determine if the licensee identified and corrected problems related to postmaintenance

testing.

• August 4, 2006, safety injection Pump B

• August 17, 2006, emergency diesel Generator B

• August 21, 2006, technical support center un-interruptible power supply

• August 31, 2006, component cooling water Pump A

• September 7, 2006, emergency diesel Generator A

-16- Enclosure

• September 28, 2006, main steam isolation valve actuation logic 15 Vdc power

supply

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors reviewed the USAR, procedure requirements, and TSs to ensure that the

listed surveillance activities demonstrated that the SSCs tested were capable of

performing their intended safety functions. The inspectors either witnessed or reviewed

test data to verify that the following significant surveillance test attributes were

adequate: (1) preconditioning; (2) evaluation of testing impact on the plant;

(3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead

controls; (7) test data; (8) testing frequency and method demonstrated TS operability;

(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of

American Society of Mechanical Engineers code requirements; (12) updating of

performance indicator data; (13) engineering evaluations, root causes, and bases for

returning tested SSCs not meeting the test acceptance criteria were correct;

(14) reference setting data; and (15) annunciators and alarms setpoints. The inspectors

also verified that the licensee identified and implemented any needed corrective actions

associated with the surveillance testing:

• July 20, 2006, Surveillance STS JE-003B, Diesel Generator NE02 Day Tank

Water Removal, Revision 11A

• July 27, 2006, Surveillance STN EJ-001B, Leakage Inspection Program of RHR

System, Revision 0

• July 27, 2006, Surveillance STS EJ-100B, RHR System Inservice Pump B Test,

Revision 25

• July 27, 2006, Surveillance STS EJ-208B, Train B RHR Inservice Valve Testing,

Revision 2

• September 7, 2006, Surveillance STS IC-615A, Slave Relay Test K615 Train A

Safety Injection, Revision 19

Documents reviewed by the inspectors included:

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• Surveillance STS JE-003B, Diesel Generator NE02 Day Tank Water Removal,

Revision 11A

• Surveillance STN EJ-001B, Leakage Inspection Program of RHR System,

Revision 0

• Surveillance STS EJ-100B, RHR System Inservice Pump B Test, Revision 25

• Surveillance STS EJ-208B, Train B RHR Inservice Valve Testing, Revision 2

• Surveillance STS IC-615A, Slave Relay Test K615 Train A Safety Injection,

Revision 19

• Wolf Creek Generating Station USAR, Revision 19

The inspectors completed five samples.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a. Inspection Scope

The inspectors reviewed the USAR, plant drawings, procedure requirements, and TSs

to ensure that the temporary modification was properly implemented. The inspectors:

(1) verified that the modification did not have an affect on system operability/availability,

(2) verified that the installation was consistent with the modification documents,

(3) ensured that the postinstallation test results were satisfactory and that the impact of

the temporary modification on permanently installed SSCs were supported by the test,

(4) verified that the modifications were identified on control room drawings and that

appropriate identification tags were placed on the affected drawings, and (5) verified that

appropriate safety evaluations were completed. The inspectors verified that the

Licensee identified and implemented any needed corrective actions associated with

temporary modifications:

• September 5, 2006, Tavg element 2 wiring change (Temporary Modification

Order 05-018-SB-00)

Documents reviewed by the inspectors included:

• Temporary Modification Order 05-018-SB-00

• Drawing M-12BB01, Piping & Instrumentation Diagram Reactor Coolant System,

Revision 25

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• Drawing 8809D51, Thot Loop Protection I Card Frame Cabinet Interconnecting

Wiring Diagram, Revision 5A

• Work Orders 05-278177 and 05-278455

The inspectors completed one sample.

b. Findings

No findings of significance was identified.

Cornerstone: Emergency Preparedness

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

a. Inspection Scope

The inspector performed an in-office review of Revision 7 to Wolf Creek Generating

Station Emergency Plan Implementing Procedure Form APF 06-002-01, "Emergency

Action Levels," received July 12, 2006. This revision updated the bases for Emergency

Action Level 9, "Loss of Plant Control/Security Compromise," to correctly describe the

classification of a hostile force located in the licensee protected area, in accordance

with NRC Bulletin 2005-002, "Emergency Preparedness and Response Actions for

Security-Based Events."

The revision was compared to the 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; to the criteria of Nuclear

Energy Institute (NEI) 99-01, "Methodology for Development of Emergency Action

Levels," Revision 2; to NRC Bulletin 2005-002; and to the standards in 10 CFR 50.47(b)

to determine if the revision was adequately conducted following 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 changes; therefore, these revisions are subject to

future inspection.

Documents reviewed by the inspectors included:

• Emergency Plan Implementing Procedure Form APF 06-002-01, Emergency

Action Levels, Revision 7

• NRC Bulletin 2005-002, Emergency Preparedness and Response Actions for

Security-Based Events

• NUREG-0654, Criteria for Preparation and Evaluation of Radiological

Emergency Response Plans and Preparedness in Support of Nuclear Power

Plants, Revision 1

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• NEI 99-01, Methodology for Development of Emergency Action Levels,

Revision 2

The inspector completed one sample.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope

For the below listed drill and simulator-based training evolution contributing to

drill/exercise performance and emergency response organization performance

indicators, the inspectors: (1) observed the training evolution to identify any

weaknesses and deficiencies in classification, notification, and protective action

requirements development activities; (2) compared the identified weaknesses and

deficiencies against licensee identified findings to determine whether the licensee is

properly identifying failures; and (3) determined whether licensee performance is in

accordance with the guidance of the NEI 99-02, Regulatory Assessment Indicator

Guideline, Revision 4, acceptance criteria.

• July 20, 2006, dropped fuel assembly leads to radiological emergency

Documents reviewed by the inspectors included:

• Emergency Planning Drill 06-SA-02

• NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 4

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

a. Inspection Scope

Cornerstone: Mitigating Systems

The inspectors sampled licensee submittals for the performance indicator listed below

for the period March 2004 through May 2006. The definitions and guidance of

NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 4, were used to verify

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the licensees basis for reporting each data element in order to verify the accuracy of

performance indicator data reported during the assessment period. The inspectors

reviewed licensee event reports, monthly operating reports, and operating logs as part

of the assessment. Licensee performance indicator data were also reviewed against

the requirements of Procedure AP 26A-007, "NRC Performance Indicators," Revision 4,

and "Performance Improvement and Learning Desktop Instruction, NRC Performance

Indicator Program Owner Guidance, Revision 2. The inspectors reviewed various

licensee indicator input information to determine the accuracy and completeness of the

performance indicator.

C Safety system functional failures

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample in this cornerstone.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

.1 Routine Review of Identification and Resolutions of Problems

a. Inspection Scope

The inspectors performed a daily screening of items entered into the licensee's CAP.

This assessment was accomplished by reviewing work requests, work orders, and

performance improvement requests and attending corrective action review and work

control meetings. The inspectors: (1) verified that equipment, human performance, and

program issues were being identified by the licensee at an appropriate threshold and

that the issues were entered into the CAP; (2) verified that corrective actions were

commensurate with the significance of the issue; and (3) identified conditions that might

warrant additional followup through other baseline inspection procedures.

b. Findings

No findings of significance were identified.

.2 Selected Issue Followup

a. Inspection Scope

In addition to the routine review, the inspectors selected the below listed issue for a

more in-depth review. The inspectors considered the following 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

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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.

• May 28, 2006, Condition Report 2006-000589 refueling water storage

tank (RWST) level increase

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

Introduction: A Green self-revealing NCV of TS 5.4.1.a was identified for the failure to

close Valves EC-V025 and -V033 during a lineup to recirculate the RWST through the

spent fuel pool (SFP) cleanup system. As a result, approximately 1200 gallons of water

was pumped from the SFP to the RWST.

Description: On May 27, 2006, the RWST was placed into recirculation through the SFP

cleanup system using Procedure SYS EC-121, Recirculation of the RWST Through the

Fuel Pool Cleanup System, Revision 11, for maintenance purposes. Approximately

25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> after placing the system into recirculation, the control room received

annunciator alarm RWST Lev HILO. Control room indication showed that the RWST

level had increased approximately 0.4 percent. After recognizing that placing the RWST

into recirculation was the only change that had been made to the system, station

operators were dispatched to determine the cause of the alarm. It was discovered that

the SFP level had decreased approximately 1 inch since placing the RWST into

recirculation. The control room directed station operators to verify the valve lineup and

discovered that Valves EC-V0025 and -V0033 were not fully closed. This resulted in an

unexplained rise in RWST level and a lowering of SFP level. Both valves were

subsequently fully closed and levels were stabilized. These valves are used to isolate

the SFP cooling heat exchanger from the SFP cleanup system during recirculation of

the RWST. These two systems were cross-connected for approximately 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br />,

which resulted in approximately 1200 gallons of SFP water being transferred to the

RWST.

The licensee noted that difficult manually-operated valves were not being identified and

entered into the CAP; therefore, the licensee identified the failure to enter the difficult

manually-operated valves into the CAP as the root cause. Due to the lack of

documentation in CAP, the evaluation noted that the most probable cause was failure to

fully close both valves. However, the apparent cause evaluation and corrective actions

failed to address the procedural compliance and human performance aspects of why the

valves were not fully closed. Based on followup interviews by the inspectors, the plant

operators stated that the valves were operated with little difficulty and the procedure

contains a caution that leakage pass-through Valves EC-V025 and -V033 will allow

water to transfer from the SFP to the RWST. It was also noted that the operator did

perform a self-check, but failed to ask for a peer-check, even though one was available.

-22- Enclosure

Analysis: The failure to completely close Valves EC-V025 and -V033 was considered a

performance deficiency. This finding is more than minor because it is associated with

the barrier integrity cornerstone attribute of configuration control and affected the

cornerstone objective to maintain functionality of the SFP system. Using Manual

Chapter 0609, Significance Determination Process, Phase 1 worksheets, the

inspectors determined that the finding is only of very low significance because the

finding only affected the barrier function of the SFP. The inspectors also determined

that this finding has crosscutting aspects in the problem identification and resolution

area associated with the CAP, based on the failure to identify and enter issues into the

CAP with a low threshold.

Enforcement: TS 5.4.1.a, Procedures, requires that written procedures be

established, implemented, and maintained covering the activities specified in

Appendix A, Typical Procedures for Pressurized Water Reactors, of Regulatory

Guide 1.33, Quality Assurance Program Requirements, February 1978. Appendix A,

Item 3.h, requires procedures for SFP cooling system operation. Station

Procedure SYS EC-121, Recirculation of the RWST Through the Fuel Pool Cleanup

System, Revision 11, step 6.1.3, requires that Valves EC-V025 and -V033 be closed

when placing the RWST in recirculation through the SFP cleanup system. Contrary to

the above procedure, on May 27, 2006, an operator failed to close Valves EC-V025 and

-V033. Because this finding is of very low safety significance and was entered into the

licensee's CAP as Condition Report 2006-000589, this violation is being treated as an

NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy:

NCV 05000482/2006004-02, Failure to completely close SFP valves resulted in a loss

of SFP water inventory.

4OA3 Followup of Events and Notices of Enforcement Discretion (71153)

Personnel Performance During Nonroutine Evolutions, Events and Transients

a. Inspection Scope

The inspectors: (1) reviewed operator logs, plant computer data, and/or strip charts for

the below listed evolutions to evaluate operator performance in coping with nonroutine

events and transients; (2) verified that operator actions were in accordance with the

response required by plant procedures and training; and (3) verified that the licensee

has identified and implemented appropriate corrective actions associated with personnel

performance problems that occurred during the events sampled.

• On June 22, 2006, the inspectors observed site response to a portable air

monitor alarm in the radwaste building at the 1976 foot level. Following the start

of a volume control tank purge on the chemical volume control system, the purge

was secured due to unexpected excessive moisture in the oxygen flow meter to

the recombiner inlet. After approximately 10 minutes of draining the moisture,

the purge was re-initiated. Approximately 40 minutes after restarting the purge,

airborne activity levels increased in the radwaste building and the volume control

tank purge was secured. The licensee determined that the unexpected airborne

activity was caused by opening Valve HA-V0706 to drain the moisture which

-23- Enclosure

provided a flow path of trapped volume control tank gases from the waste gas

compressor to atmosphere. The operation of Valve HA-V0706 was not

controlled by procedure and was not compatible with the purge system lineup at

the time. This resulted in an unplanned monitored release inside the radwaste

building. Section 4OA7 describes enforcement aspects of this event.

• On September 14, 2006, the inspectors reviewed the response of the control

room operators to a loss of charging flow. During surveillance testing of check

valves in the chemical and volume control system, the control room operators

received the charging low flow and reactor coolant pump seal injection low flow

annunciators, in addition to observing a small transient on pressurizer level and

volume control tank level and temperature. The control room recognized that

charging flow was lost and responded by starting the opposite train centrifugal

charging pump. This action restored normal charging flow and stabilized

pressurizer level. Miscommunication between two station operators resulted in

an isolation of the running charging header with the opposite charging header

secured.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

Loss of Charging Flow

Introduction: A self-revealing Green NCV of TS 5.4.1.a involving the licensee's failure to

follow a procedure that resulted in a loss of coolant charging flow during a planned

surveillance.

Description: On September 14, 2006, the licensee performed surveillance

Procedure STS BG-210, "CVCS Inservice Check Valve Test, Revision 22. This

procedure tested check valve operability for multiple trains of the chemical and volume

control system. The licensee conducted a pre-evolution brief in accordance with

Procedure AP 22-001, Conduct of Pre-Job Briefs and Post-Job Briefs, Revision 8;

however, an operations trainee designated to provide peer checks did not attend the

brief. Following the pre-evolution brief, three operators were dispatched to the auxiliary

building with copies of the applicable procedures.

The operators successfully completed testing of the check valves associated with the

Train A centrifugal charging pump. Procedure STS BG-210 then directed the Train B

cooling charging pump be placed in service in accordance with Procedure SYS BG-201,

"Shifting Charging Pumps," Revision 41. With the Train A centrifugal charging pump

running, the control room directed the station operators to open Valve BG8483C,

cooling charging Pump B discharge isolation valve. Following the opening of

Valve BG8483C, Procedure SYS BG-201 required six actions to be completed prior to

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closing Train A charging header isolation Valve BG8483A. Included in these steps was

a requirement to start the Train B centrifugal charging pump and stop the Train A

centrifugal charging pump.

Miscommunication between two of the station operators resulted in confusion as to what

step in the procedure was required next. Without direction from the control room and

without receiving a peer check, a station operator closed Valve BG8483A, the Train A

centrifugal charging pump discharge isolation valve. Although a field copy of the

procedure was available, it was not referenced. This resulted in isolating the charging

flow to the reactor coolant system and reactor coolant pump seal injection flow. Several

annunciators were received in the control room, including the charging low flow and the

reactor coolant pump seal injection low flow alarms. Additionally, a small transient was

observed on pressurizer level and volume control tank level and temperature. The

control room recognized that charging flow had been lost and reactor coolant pump seal

injection flow had been reduced and immediately started Train B centrifugal charging

pump. This action prevented a complete loss of reactor coolant pump seal injection

flow, restored normal charging flow, and stabilized pressurizer level.

Analysis: The failure to follow station procedures was considered a performance

deficiency. This finding was more than minor because it affected the human

performance attribute of the initiating events cornerstone and the cornerstone objective

to limit the likelihood of those events that upset plant stability and challenge critical

safety functions. Using Manual Chapter 0609, Significance Determination Process,

Phase 1 worksheets, this finding screened to a Phase 2 analysis because it affected

both the initiating events and mitigating system cornerstones. The inspectors performed

a Phase 2 analysis using Appendix A, "Technical Basis For At Power Significance

Determination Process," of Manual Chapter 0609, "Significance Determination Process,"

and the Phase 2 worksheets for the Wolf Creek Generating Station. The inspectors

assumed that the loss of all charging and seal injection flow would lead to loss of reactor

coolant system inventory and ultimately a plant trip. Dominant sequences from the

Phase 2 analysis were a plant trip with a loss of main and auxiliary feedwater combined

with a loss of early inventory high pressure injection, a loss of high pressure

recirculation, and a loss of primary feed and bleed. Based on the results of the Phase 2

analysis, the finding is determined to have very low safety significance. The Phase 2

analysis was verified by a Region IV senior reactor analyst. The inspectors also

determined that the finding has crosscutting aspects in the area of human performance

associated with work practices because the operators failed to use appropriate human

error prevention techniques, such as self-checking, peer-checking, and not proceeding

in the face of uncertainty.

Enforcement: TS 5.4.1.a, Procedures, requires that written procedures be

established, implemented, and maintained covering the activities specified in

Appendix A, Typical Procedures for Pressurized Water Reactors, of Regulatory

Guide 1.33, Quality Assurance Program Requirements, February 1978. Appendix A,

Item 3.n, requires procedures governing operation of the chemical and volume control

system. Procedure SYS BG-201, "Shifting Charging Pumps," Revision 41, step 6.4.6

requires that if centrifugal charging Pump A is running, then start centrifugal charging

Pump B prior to step 6.4.7, which requires Valve BG8482A to be locked closed.

-25- Enclosure

Contrary to the above, an operator shut Valve BG8483A, the centrifugal charging

Pump A discharge isolation valve, prior to establishing Train B charging flow. Because

this violation was of very low safety significance and was entered in the CAP as

Condition Report 2006-002030, this violation is being treated as an NCV consistent with

Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2006004-03, Failure to

follow procedure results in loss of coolant charging flow.

4OA5 Other Activities

.1 (Closed) Temporary Instruction 2515/169, Mitigating Systems Performance Index

(MSPI) Verification

a. Inspection Scope

During this inspection period, the inspectors completed a review of the licensees

implementation of the MSPI in accordance with the guidance provided in Temporary

Instruction 2515/169. The review examined the licensees implementation Document,

WCNOC-163, MSPI Basis Document, Revision 1, and verified that established system

boundaries and monitored components were consistent with guidance provided in

NEI 99-02, Reactor Oversight Process Performance Indicators, Revision 4. The

inspectors examined surveillances that the licensee determined do not render the train

unavailable for greater than 15 minutes and are, therefore, not used in unavailability

calculations. The inspectors also examined activities identified by the licensee that do

not render an MSPI train unavailable due to credit for operator recovery. As part of this

review, the recovery actions were verified to be uncomplicated and contained in written

procedures.

Additionally, the inspectors reviewed the baseline MSPI unavailability time using plant

specific values for the period of 2002 to 2004. The verification included all planned and

unplanned unavailability. The plant-specific data for 2005 to 2006 was also reviewed to

ensure the licensee properly accounted for the actual unavailability hours of MSPI

systems. For the same period, the MSPI component unreliability data was examined to

ensure the licensee identified all failures of monitored components. The accuracy and

completeness of the reported unavailability and unreliability data was verified by

reviewing out-of-service logs, operating logs, and corrective action documents. The

unavailability and unreliability data was compared with performance indicator data

submitted to the NRC to ensure that any discrepancies would not result in a change to

the index color.

b. Findings

No findings of significance were identified. This completes the inspection requirements

for this TI.

-26- Enclosure

4OA6 Meetings, Including Exit

On July 31, 2006, the inspector presented the inspection results to Mr. T. East,

Superintendent of Emergency Planning, who acknowledged the findings. The inspector

confirmed that proprietary information was not provided or examined during the

inspection.

On August 31, 2006, the inspectors conducted a debrief meeting to present the licensed

operator requalification inspection results to the Licensee's management team. The

licensee was informed that a final exit for the inspection would be conducted after the

requalification program was completed and the NRC had reviewed the final results. On

September 20, 2006, a final exit, which described the inspection results, was conducted

by the inspectors via telephone with Ms. M. Guyer, Superintendent of Operations

Training. The inspectors asked the licensee whether any materials examined during the

inspection should be considered proprietary. No proprietary information was identified.

On October 6, 2006, the resident inspectors presented the inspection results of the

inspections to Mr. S. Hedges, Vice President Operations and Plant Manager, and other

members of the licensee's management staff. The licensee acknowledged the findings

presented. The inspectors verified that no proprietary information was provided during

the inspection.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee

and are violations of NRC requirements which meet the criteria of Section VI of the

NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.

• TS 5.4.1.a, Procedures, requires that written procedures be established,

implemented, and maintained covering the activities specified in Appendix A,

Typical Procedures for Pressurized Water Reactors, of Regulatory Guide 1.33,

Quality Assurance Program Requirements, February 1978. Appendix A,

Item 7.c, requires procedures for gaseous effluent system control. Contrary to

this requirement, Procedures SYS HA-200, Gaseous Radwaste System

Operations, Revision 22, and SYS HA-205, Operation of Gas Analyzer Racks,

Revision 23, did not control the use of Valve HA-V0706 to drain moisture from

the flow meters. However, on June 22, 2006, licensee personnel operated this

valve, which resulted in an unplanned release. This event is described in the

CAP as Condition Report 2006-000398. This finding was determined to be of

very low safety significance because it did not affect the licensees ability to

assess dose impact to the public.

• License Condition 2.C.(5)(a) states that the licensee shall maintain in effect all

provisions of the approved fire protection program as described in the Standard

Nuclear Unit Power Plant System Final Safety Analysis Report for the facility

through Revision 17, the Wolf Creek site addendum through Revision 15, and as

approved in the safety evaluation report through Supplement 5. The fire

protection program states that it will comply with the technical requirements of

-27- Enclosure

Appendix R,Section III.G.2 to 10 CFR Part 50, which requires cables whose fire

damage could prevent the operation of safe shutdown functions be physically

protected from fire damage. The fire protection program states that 3-hour fire

barriers are required for Fire Areas C-35 and A-6. Contrary to this requirement,

the licensee failed to ensure that the required 3-hour fire barriers between Fire

Areas C-35 and A-6 were functional without compensatory measures in place.

The fire barriers as installed provided approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of fire endurance.

This issue is described in the CAP as Performance Improvement

Request 2006-001970. This finding was determined to be of very low safety

significance because the fire barrier was assigned a fire containment moderate

degradation rating since there was still some defense-in-depth benefit and it

provided a minimum of 20 minutes fire endurance for the areas.

ATTACHMENT: SUPPLEMENTAL INFORMATION

-28- Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. J. Garrett, Vice President Engineering

S. E. Hedges, Vice President Operations and Plant Manager

R. A. Muench, President and Chief Executive Officer

K. Scherich, Director Engineering

M. Sunseri, Vice President Oversight

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000482/2006004-01 NCV Inadequate inspections of potentially defective pressure

transmitter (Section 1R15)05000482/2006004-02 NCV Failure to completely close SFP valves resulted in a loss

of SFP water inventory (Section 4OA2.2)05000482/2006004-03 NCV Failure to follow procedure results in loss of coolant

charging flow (Section 4OA3)

DOCUMENTS REVIEWED

In addition to the documents referred to in the inspection report, the following documents were

selected and reviewed by the inspectors to accomplish the objectives and scope of the

inspection and to support any findings:

Section 1R05 Fire Protection

Procedure AP 10-102, Control of Combustible Materials, Revision 10

Procedure AP 10-106, Fire Preplans, Revision 3

Procedure AP 21B-003, Control of Temporary Equipment, Revision 5

Procedure E-1F9905, Fire Hazard Analysis, Revision 0

Surveillance STN KC-206, Spray and Sprinkler System Functional Testing, Revision 13

Condition Report 2006-002256

Section 1R07 Heat Sink Performance

Procedure MP EN-171, ESW Train A Post LOCA Flow Balance, Revision April 1994, performed

October 20, 1994

A-1 Attachment

Procedure TMP TS-50, ESW Train B Post LOCA Flow Balance, Revision 0, performed

November 1, 1991

Surveillance STN EF 022A, ESW Train A Post LOCA Flow Balance, Revision 4, performed

May 10, 2005

Procedure TMP EN-173, ESW Train A Post LOCA Flow Balance, Revision 1, performed

October 19, 1994

Surveillance STN EF 022A, ESW A Post LOCA Flow Balance, Revision 1, performed May 9,

2005

Surveillance STN PE-037A, ESW Train A Heat Exchanger Flow and DP Trending, Revision 9,

performed February 20, 2006

Surveillance STN PE-037A, ESW Train A Heat Exchanger Flow and DP Trending, Revision 10,

performed August 8, 2006

Surveillance STN PE-037B, ESW Train A Heat Exchanger Flow and DP Trending, Revision 10,

performed February 12, 2006

Surveillance STN PE-038, Containment Cooler Performance Test, Revision 7, performed

April 19, 2004

Proto-Power Corporation User Documentation for Heat Exchanger Modeling Software,

Revision 4.10

Calculation SA-90-057, Specific Acceptance Criteria and Operations of the Containment Fan

Coolers, Revision 0

EDI 23L-004, Proto-HX Heat Exchanger Test Data Uncertainty, Desk Top Instruction,

Revision 0

EDI 23L-003, Proto-HX Heat Exchanger Testing Software, Revision 0

Calculation AN-97-005, Containment Temperature and Pressure Response, Revision 0

Calculation M-620-00117 W01, Cooling Coil Curves, September 10, 1991

Section 1R13 Maintenance Risk Assessments and Emergent Work Control

Procedure AP 22C-003, Operational Risk Assessment Program, Revision 11

2006 Work Week 308 risk profile

2006 Work Week 311 risk profile

2006 Work Week 313 risk profile

Work Order 278072013

A-2 Attachment

Section 1R19 Postmaintenance Testing

Conditional Release for Installation/Testing 06-288426-002

Procedure AP 16E-002, Post Maintenance Testing Development, Revision 5

Procedure AP 24D-003, Receipt Inspections, Revision 9A

Purchase Order 736014, Revision 1

Procedure SYS EF-200, Operation of the ESW System, Revision 26

Procedure SYS KJ-123, Post Maintenance Run of Emergency Diesel Generator A, Revision 35

Surveillance STS KJ-011B, DG NE02 24 Hour Run, Revision 16

Surveillance STS KJ-015A, Manual/Auto Fast Start, Sync and Loading of EDG NE01,

Revision 21

Work Orders 05-279245-000, 06-287374-000, 06-288426-000, and 06-288429-000

Section 4OA1 Performance Indicator Verification

Engineering Desktop Instruction EDI 23M-050, Monitoring Performance to Criteria and Goals,

Revision 3

Licensee Event Reports 2004-002-00, -006-00, 2005-002-00, -004-00, -005-00, and

2006-002-00

NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 4

Performance Improvement and Learning Desktop Instruction, NRC Performance Indicator

Program Owner Guidance, Revision 2

Performance Improvement Requests 2004-2765 and 2005-2152

Procedure AP 26A-007, NRC Performance Indicators, Revision 4

Section 4OA2 Identification and Resolution of Problems

Procedure SYS EC-121, Recirculation of the RWST Through the Fuel Pool Cleanup System,

Revision 11

Reportability Evaluation Request 2006-010

A-3 Attachment

Condition Reports:

CR 2006-1549 CR 2006-2062 CR 2006-2196

CR 2006-1750 CR 2006-2072 CR 2006-2204

CR 2006-1752 CR 2006-2074 CR 2006-2209

CR 2006-1764 CR 2006-2092 CR 2006-2211

CR 2006-1796 CR 2006-2097 CR 2006-2213

CR 2006-1829 CR 2006-2103 CR 2006-2217

CR 2006-1864 CR 2006-2115 CR 2006-2222

CR 2006-1886 CR 2006-2125 CR 2006-2223

CR 2006-1895 CR 2006-2133 CR 2006-2231

CR 2006-1899 CR 2006-2159 CR 2006-2233

CR 2006-1900 CR 2006-2161 CR 2006-2281

CR 2006-1904 CR 2006-2175 CR 2006-2282

CR 2006-1925 CR 2006-2178 CR 2006-2321

CR 2006-1946 CR 2006-2186

CR 2006-1967 CR 2006-2189

CR 2006-2028 CR 2006-2190

CR 2006-2054 CR 2006-2194

Section 4OA3 Followup of Events and Notices of Enforcement Discretion

Condition Reports 2006-1752 and 2006-2030

Procedure AP 15C-002, Procedure Use and Adherence, Revision 22

Procedure AP 21-001, Conduct of Operations, Revision 36

Procedure AP 22-001, Conduct of Pre-Job Briefs and Post-Job Briefs, Revision 8

Procedure SYS BG-201, Shifting Charging Pumps, Revision 41

Surveillance STS BG-210, CVCS Inservice Check Valve Test, Revision 22

Procedure SYS HA-200, Gaseous Radwaste System Operations, Revision 22

Procedure SYS HA-205, Operation of Gas Analyzer Racks, Revision 23

Section 4OA5 Other Activities

MSPI verification of unavailability data changes due to CW and critical hours

MSPI verification of unavailability input/baseline data

MSPI verification of unreliability input/baseline data

WCNOC-163, Mitigating System Performance Index (MSPI) Basis Document, Revision 1

Surveillance STN OQT-001A, Operations A Train Quarterly Tasks, Revision 23

Surveillance STS AL-101, MDAFW Pump A Inservice Pump Test, Revision 35

Surveillance STS AL-104, TDAFW ESF Response Time, Flow Path Verification and Check

Valve Testing, Revision 13

Surveillance STS AL-201C, Turbine Driven Auxiliary Feedwater System Inservice Valve Test,

Revision 4

A-4 Attachment

Surveillance STS AL-212, MDAFP Comprehensive Pump Testing, Flow Path Verification and

CV Testing, Revision 10

Surveillance STS BG-205, CVCS Inservice Valve Test, Revision 20

Surveillance STS BG-212B, Train B CCP Discharge Check Valve Inservice Test, Revision 2

Surveillance STS IC-208, 4KV Loss of Voltage and Degraded Voltage TADOT NB02 Bus -

Separation Group 4, Revision 2A

Surveillance STS IC-634B, Slave Relay Test - Train B Steam/Feed Isolation, Revision 16

Surveillance STS IC-805B, Channel Calibration of NB02 Grid Degraded Voltage, Time Delay

Trip, Revision 10

LIST OF ACRONYMS

CAP corrective action program

MSPI mitigating systems performance index

NCV noncited violation

NEI Nuclear Energy Institute

NRC Nuclear Regulatory Commission

RWST refueling water storage tank

SFP spent fuel pool

SSC structure, system, and component

TS Technical Specification

USAR Updated Safety Analysis Report

A-5 Attachment