ML100430713

IR 05000482-09-005, on 10/01/2009 - 12/31/2009; Wolf Creek Generating Station, Integrated Resident and Regional Report; Fire Protection, Inservice Inspection Activities; Maintenance Risk Assessments and Emergent Work Controls

ML100430713
Person / Time
Site:	Wolf Creek
Issue date:	02/11/2010
From:	Geoffrey Miller NRC/RGN-IV/DRP/RPB-B
To:
References
ea-10-004, EA-10-020
Download: ML100430713 (118)

See also: IR 05000482/2009005

Text

February 11, 2010

EA-10-004

EA-10-020

Matthew W. Sunseri, 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 05000482/2009005 AND NOTICE OF VIOLATIONS

Dear Mr. Sunseri:

On December 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an

inspection at your Wolf Creek Generating Station. The enclosed integrated inspection report

documents the inspection findings, which were discussed on January 14, 2010, with you and

other members of your staff.

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

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

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

personnel.

Based on the results of this inspection, the NRC has identified two issues that were evaluated

under the risk significance determination process as having very low safety significance (green).

The NRC has also determined that violations are associated with these issues. One violation

involved failure to implement corrective actions to address refueling water storage tank leakage

(EA-10-004). The second violation involved failure to correct an inadequate reactor vessel head

vent path (EA-10-020). These violations were evaluated in accordance with the NRC

Enforcement Policy included on the NRCs Web site at www.nrc.gov/about-

nrc/regulatory/enforcement/enforce-pol.html.

The violations are being cited in the enclosed Notice of Violations (Notice) and the

circumstances surrounding them are described in detail in the subject inspection report. The

violations are being cited in the Notice because Wolf Creek Generating Station failed to restore

compliance within a reasonable time after the violations were identified in NRC Inspection

Reports05000482/2007003-006 and 05000482/2008004-007, as specified in Section VI.A.1 of

the NRC Enforcement Policy.

You are required to respond to this letter and should follow the instructions specified in the

enclosed Notice when preparing your response. The NRC will use your response, in part, to

UNITED STATES

NUCLEAR REGULATORY COMMISSION

R E GI ON I V

612 EAST LAMAR BLVD, SUITE 400

ARLINGTON, TEXAS 76011-4125

Wolf Creek Nuclear Operating Corporation - 2 -

- 2 -

determine whether further enforcement action is necessary to ensure compliance with

regulatory requirements.

Based on the results of this inspection, the NRC has also determined that one additional

Severity Level IV violation of NRC requirements occurred. This report also documents

12 NRC identified and one self-revealing finding 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, are

listed in this report. However, because of the very low safety significance and because they are

entered into your corrective action program, the NRC is treating these findings as noncited

violations, consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the

violations or the significance of the noncited violations, you should provide a response within

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

Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with

copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E.

Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, D.C. 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, and its

enclosure, will be 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).

Sincerely,

/RA/

Geoffrey B. Miller, Chief

Project Branch B

Division of Reactor Projects

Docket No. 50-482

License No. NPF-42

Enclosure

Inspection Report 05000482/2009005

w/Attachment: Supplemental Information

Wolf Creek Nuclear Operating Corporation - 3 -

- 3 -

cc w/Enclosure:

Vice President Operations/Plant Manager

Wolf Creek Nuclear Operating Corporation

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 Corporation

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

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

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

Wolf Creek Nuclear Operating Corporation - 4 -

- 4 -

Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

Deputy Regional Administrator (Chuck.Casto@nrc.gov)

DRP Director (Dwight.Chamberlain@nrc.gov)

DRP Deputy Director (Anton.Vegel@nrc.gov)

DRS Director (Roy.Caniano@nrc.gov)

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

Senior Resident Inspector (Chris.Long@nrc.gov)

Site Secretary (Shirley.Allen@nrc.gov)

Branch Chief, DRP/B (Geoffrey.Miller@nrc.gov)

Senior Project Engineer, DRP/B (Rick.Deese@nrc.gov)

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

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

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

Team Leader, DRP/TSS (Chuck.Paulk@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

Only inspection reports to the following:

DRS/TSB STA (Dale.Powers@nrc.gov)

L. Trocine, OEDO RIV Coordinator (Leigh.Trocine@nrc.gov)

ROPreports

File located: R:\\_REACTORS\\_WC\\2009\\WC20090005-RP-CML.doc ML 100430713

SUNSI Rev Compl.

Yes No

ADAMS

Yes No

Reviewer Initials

GBM

Publicly Avail

Yes No

Sensitive

Yes : No

Sens. Type Initials

GBM

RI:DRP/

SRI:DRP/

SPE:DRP/

C:DRS/EB1

C:DRS/EB2

CAPeabody

CMLong

RDeese

TFarnholtz

NFOKeefe

/RA/GMiller for

/RA/GMiller for

/RA/

/RA/

/RA/

01/22/2010

01/29/2010

02/05/2010

02/05/2010

02/05/2010

C:DRS/OB

C:DRS/PSB1

C:DRS/PSB2

RIV:ACES

C:DRP/

SGarchow

MPShannon

GEWerner

RKellar

GBMiller

/RA/

/RA/

/RA/

/RA/

/RA/

02/09/2010

02/08/2010

02/09/2010

02/09/2010

02/11010

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

- 1 -

Enclosure 1

NOTICE OF VIOLATIONS

Wolf Creek Nuclear Operating Corporation

Docket: 50-482

Wolf Creek Generating Station

License: NPF-42

EA-10-004

EA-10-020

During an NRC inspection conducted October 1 through December 31, 2009, two violations of

NRC requirements were identified. In accordance with the NRC Enforcement Policy, the

violations are listed below:

A.

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires,

in part, that measures shall be established to assure that conditions adverse

to quality are promptly identified and corrected.

Contrary to the above, from 1998 to December 31, 2009, the measures

established by Wolf Creek did not correct a condition adverse to quality.

Specifically, Wolf Creek did not correct leakage from the refueling water

storage tank.

This violation is associated with a Green Significance Determination Process finding

(EA-10-004).

B.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that

the design basis is correctly translated into specifications, drawings, and procedures.

The design basis of the reactor vessel head vent is to allow noncondensable gases to

escape to the pressurizer during shutdown conditions.

Contrary to the above, from December 2, 2003, to December 31, 2009, Wolf Creek

failed to ensure the design basis of the reactor vessel head vent was correctly translated

into specifications, drawings and procedures. Specifically, Wolf Creek designed and

installed a reactor vessel head permanent vent piping modification which failed to vent

noncondensable gases to the pressurizer during shutdown operations.

This resulted in the formation of voids in the reactor vessel head while the plant was

shutdown and depressurized in successive refueling outages.

This violation is associated with a Green Significance Determination Process finding

(EA-10-020).

Pursuant to the provisions of 10 CFR 2.201, Wolf Creek Nuclear Operating Corporation is

hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory

Commission, ATTN: Document Control Desk, Washington, DC 20555, with a copy to the

Regional Administrator, Region IV, and a copy to the NRC Senior Resident Inspector at the

facility that is the subject of this Notice of Violation (Notice), within 30 days of the date of the

letter transmitting this Notice. This reply should be clearly marked as a "Reply to Notice of

Violation EA-10-004," EA 10-020, and should include for each violation (1) the reason for the

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Enclosure 1

violation, or, if contested, the basis for disputing the violation or severity level, (2) the corrective

steps that have been taken and the results achieved, (3) the corrective steps

That will be taken to avoid further violations, and (4) the date when full compliance will be

achieved. Your response may reference or include previous docketed correspondence, if the

correspondence adequately addresses the required response. If an adequate reply is not

received within the time specified in this Notice, an Order or a Demand for Information may be

issued as to why the license should not be modified, suspended, or revoked, or why such other

action as may be proper should not be taken. Where good cause is shown, consideration will

be given to extending the response time.

If you contest this enforcement action, you should also provide a copy of your response, with

the basis for your denial, to the Director, Office of Enforcement, United States Nuclear

Regulatory Commission, Washington, DC 20555-0001.

Because your response will be made available electronically for public inspection in the NRC

Public Document Room or from the NRCs document system (ADAMS), accessible from the

NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should not

include any personal privacy, proprietary, or safeguards information so that it can be made

available to the public without redaction. If personal privacy or proprietary information is

necessary to provide an acceptable response, then please provide a bracketed copy of your

response that identifies the information that should be protected and a redacted copy of your

response that deletes such information. If you request withholding of such material, you must

specifically identify the portions of your response that you seek to have withheld and provide in

detail the bases for your claim of withholding (e.g., explain why the disclosure of information will

create an unwarranted invasion of personal privacy or provide the information required by

10 CFR 2.390(b) to support a request for withholding confidential commercial or financial

information. If safeguards information is necessary to provide an acceptable response, please

provide the level of protection described in 10 CFR 73.21.

Dated this 11h day of February 2010

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Enclosure 2

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket:

05000482

License:

NPF-42

Report:

05000482/2009005

Licensee:

Wolf Creek Operating Corporation

Facility:

Wolf Creek Generating Station

Location:

1550 Oxen Lane SE

Burlington, Kansas

Dates:

October 1 through December 31, 2009

Inspectors:

C. M. Long, Senior Resident Inspector

R. A. Kopriva, Senior Reactor Inspector

J. F. Drake, Senior Reactor Inspector

D. Loveless, Senior Reactor Analyst

C. A. Peabody, Resident Inspector

S. M. Alferink, Reactor Inspector

P. A. Jayroe, Project Engineer

C. Cauffman, Operations Engineer

A. L. Fairbanks, Reactor Inspector

C. C. Alldredge, Project Engineer

G. M. Vasquez, Senior Health Physicist

D. C. Graves, Health Physicist

Approved By:

G. B. Miller, Chief, Project Branch B

Division of Reactor Projects

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Enclosure 2

SUMMARY OF FINDINGS

IR 05000482/2008005, 10/01/2009 - 12/31/2009; Wolf Creek Generating Station, Integrated

Resident and Regional Report; Fire Protection, Inservice Inspection Activities; Maintenance Risk

Assessments and Emergent Work Controls; Operability Evaluations; Plant Modifications;

Refueling Outage and Other Outage Activities; Radiation Safety; Identification and Resolution of

Problems, and Other Activities.

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

baseline inspections by a regional based inspectors. Fourteen Green and one Severity Level IV

noncited violation were identified and two Green cited violations were also identified. 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 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 identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, involving the licensees failure to

identify sources of boron leakage and document them in a corrective action document.

Specifically, prior to October 23, 2009, the licensee failed to accomplish the

requirements of Procedure AP 16F-001, Boric Acid Corrosion Control Program,

Revision 5, step 6.4.1, which states, in part, Sources of boron seepage/leakage shall

be identified/verified and documented in the applicable corrective action document.

During a boric acid walkdown, the inspectors identified 11 sources of boron leakage

which had not been previously identified and documented by the licensee. The licensee

entered this finding into their corrective action system as Condition Report 00021274.

The finding was determined to be more than minor because it was associated with the

Initiating Events Cornerstone attribute of human performance and 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. The

inspectors used Inspection Manual Chapter 0609, Significance Determination Process,

Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and

determined the finding was of very low safety significance (Green) because the issue

would not result in exceeding the technical specification limit for identified reactor

coolant system leakage or affect other mitigating systems resulting in a total loss of their

safety function. The inspectors also determined that the finding had a crosscutting

aspect in the area of problem identification and resolution, operating experience, where

the licensee did not institutionalize operating experience through changes to station

processes, procedures, equipment, and training programs [P.2.(b)] (Section 1R08.2.b).

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Enclosure 2

Green. On December 16, 2009, inspectors identified a noncited violation of 10 CFR

Part 50, Appendix B, Criterion III, Design Control, involving failure to obtain vendor

design data for a modification. In August 2009, a component cooling water modification

was made to the reactor coolant pump thermal barrier heat exchangers flow rates as a

corrective action to VIO 05000482/2009002 07 (EA-09-110). A flow rate above the

previous design value was justified by an internal memo of a vendor opinion from a

telephone conversation in 1992. The inspectors found this to be contrary to

Procedure AP 05-005, for obtaining data from vendors. The notice of violation will

remain open until full compliance has been restored. Wolf Creek consulted with

Westinghouse, confirmed the acceptability of the increased flow rate, and requested a

formal calculation. This issue is captured in Condition Report 22824.

The inspectors determined that this finding was more than minor because this issue

aligned with Inspection Manual Chapter 0612, Appendix E, example 2.f, in that the

modification relied on verbal statements to raise the allowable flow through the heat

exchanger. This is a significant deficiency in the modification package. The inspectors

determined this finding was associated with the design control attribute of the Initiating

Events Cornerstone and affected the cornerstone objective to limit the likelihood of

events that upset plant stability and challenge critical safety functions. The inspectors

evaluated the significance of this finding using Phase 1 of Inspection Manual

Chapter 0609.04 and determined that the finding was of very low safety significance

because assuming worst case degradation, the finding would not result in exceeding the

technical specification limit for identified reactor coolant system leakage and would not

have likely affected other mitigation systems resulting in a total loss of their safety

function because seal injection was available. This finding has a crosscutting aspect in

the area of human performance associated with work practices in that management was

unsuccessful in communicating expectations on procedure use and adherence in

engineering H.4.b] (Section 1R18).

Green. The inspectors identified a cited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, due to an inadequate vent path for the reactor vessel

head. The inadequate vent path resulted in the formation of voids in the reactor vessel

head during Refueling Outage 17. Failure to ensure an adequate vent path in the

reactor vessel head was the subject of a noncited violation in NRC Inspection

Report 05000482/2008004. During and after Refueling Outage 16, Wolf Creek initiated

a root cause evaluation and corrective actions to prevent occurrence. When one of the

possible root causes was disproven in Refueling Outage 17, no additional action was

taken to determine the cause of the vessel head vent blockage. However, the licensee

could not exclude blockage in the piping. This issue was entered into the corrective

action program and the licensee plans to conduct a more thorough inspection of the

piping during the next refueling outage. This issue is being tracked by the licensee as

Condition Report 22501.

The inspectors determined that the failure to provide adequate vessel head vent path to

prevent gas accumulation in the reactor vessel during depressurized plant operations

was a performance deficiency. The inspectors determined that this finding, which was

associated with the Initiating Events Cornerstone, was more than minor because if left

uncorrected, it would have become a more significant-safety concern. Specifically,

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Enclosure 2

without an adequate vent path the reactor vessel does not have an effective means of

relieving noncondensable gases to prevent a loss of reactor coolant system inventory.

The inspectors evaluated this finding using Inspection Manual Chapter 0609,

Appendix G, Attachment 1, and determined it be of very low safety significance based

upon the demonstrated availability of mitigating systems and the flooded reactor cavity

inventory. The inspectors determined the cause of the finding had a problem

identification and resolution aspect in the corrective action program. Specifically, Wolf

Creeks corrective actions were not successful to address the vent path blockage in a

timely manner P.1(d) (Section 1R20).

Green. The inspectors identified a noncited violation of License Condition 2.C.(5), Fire

Protection, for the failure to implement and maintain the approved fire protection

program. Specifically, the licensee prescribed mitigating actions in response to certain

fire scenarios that would result in a loss of circuit breaker coordination and could initiate

secondary fires in plant locations outside of the initial fire area. The licensee entered

this issue into their corrective action program as Condition Report 2008-005210.

This finding was more than minor because it was associated with the Protection Against

External Factors 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. The

risk significance of this finding was determined using Manual Chapter 0609, Appendix F,

Fire Protection Significance Determination Process. The finding was determined to be

of very low safety significance using a Phase 2 evaluation. This finding was not

assigned a crosscutting aspect because the cause was not representative of current

performance (Section 4OA5.2).

Cornerstone: Mitigating Systems

Green. The inspectors identified a cited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Action, for failure to take action to stop leakage from the base

of the refueling water storage tank or evaluate the leakage and wastage for

acceptability. Specifically, the licensee did not take actions to prevent recurring

discolored boric acid deposits for approximately 11 years. Failure to correct leakage

from the refueling water storage tank base was the subject of a noncited violation in

NRC Inspection Report 05000482/2007006. This issue was entered into the licensee's

corrective action program as Condition Report 22866.

The failure to implement corrective actions for the refueling water storage tank leakage

was a performance deficiency. The inspectors determined this issue impacted the

Mitigating Systems Cornerstone and was greater than minor because if left uncorrected,

the failure to correct the presence of boric acid leakage could become a more significant

safety concern in that continued wastage could impact tank operability. Using the

Phase 1 worksheets in Inspection Manual Chapter 0609.04, "Significance Determination

Process," the finding was determined to have very low safety significance because it did

not result in a system or component being inoperable and it did not screen as potentially

risk significant due to a seismic, flooding, or severe weather initiating event. The

inspectors identified a crosscutting aspect in the area of human performance associated

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Enclosure 2

with resources. Specifically, Wolf Creek did not maintain long-term plant safety

minimizing corrective maintenance deferrals and this long-standing equipment issue

H.2.c] (Section 1R05).

Green. The inspectors identified a noncited violation of Technical Specification 5.4.1.a,

for an inadequate Procedure AP-10-101, Control of Transient Ignition Sources. On

October 21, 2009, the inspectors observed maintenance personnel performing weld

preparation work on essential service water piping to containment cooler B using a

flapper wheel. The inspectors observed that the ignition control barriers for the hot work

were insufficient in that the sparks from the preparation work extended four to five feet

from the job site and there was no fire watch posted. On December 4, 2003, a

procedure revision inappropriately incorporated a change to the procedure where a fire

watch did not have to be posted when using wire brushes, flapper wheels, polishing

devices, or Rol-Lok type buffing pads mounted on power grinder motor drives or air

tools. The maintenance supervisor stopped the work until a fire watch was posted. The

licensee entered this into their corrective action system as Condition Report 20993.

This finding is more than minor because it affected the Mitigating Systems Cornerstone

attribute of Protection Against External Factors - Fires, and adversely affected the

cornerstone objective to ensure the availability, reliability, and capability of systems that

respond to initiating events to prevent undesirable consequences. The lack of a posted

fire watch could adversely affect the ability to achieve and maintain safe shutdown in the

event of a severe fire in the affected area. Inspection Manual Chapter 0609,

Appendix F, Fire Protection Significance Determination Process, could not be used to

effectively evaluate the finding and defense-in-depth strategies because the 2003

changes to the fire watch program affected multiple fire areas and conditions. Therefore,

in accordance with Inspection Manual Chapter 0609, Appendix M, the safety significance

was determined by regional management review who concluded that the finding was of

very low safety significance (Green). This finding was reviewed for crosscutting aspects

and none were identified. The original change occurred in 2003 and was not indicative

of current performance (Section 1R05.2).

Green. The inspectors identified a noncited violation of 10 CFR 50.65(a)(4) involving the

failure to adequately perform shutdown risk assessments during Refueling Outage 17.

Between October 10 and November 17, 2009, Wolf Creek did not appropriately consider

electrical power, decay heat removal, and containment when assessing shutdown risk.

This changed the outcome or color of the qualitative calculation on several occasions.

The licensee entered this issue in their corrective action program as Condition

Reports 22295 and 22296.

The failure to meet shutdown risk assessment requirements in the daily shutdown risk

assessment process is a performance deficiency. The inspectors determined this finding

was associated with the Mitigating Systems Cornerstone and was more than minor

because it involved incorrect risk assessment assumptions by omitting requirements

specified in committed guidance without providing justification for that omission. Such

errors of omission have the potential to change the outcome of the licensees

maintenance risk assessment as described above. Per Inspection Manual

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Enclosure 2

Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management

Significance Determination Process, licensees who only perform qualitative analyses of

plant configuration risk due to maintenance activities, the significance of the deficiencies

must be determined by an internal NRC management review using risk insights where

possible in accordance with Inspection Manual Chapter 612, Power Reactor Inspection

Reports. The NRC management review concluded that this finding was of Green safety

significance because missing risk management actions did not result in loss of key

shutdown risk functions. Additionally, the cause of the finding has a human performance

crosscutting aspect in the area associated with the resources. Specifically, Wolf Creek

did not ensure that Procedure APF 22B-001-02 was complete, accurate, and up-to-date

H.2(c) (Section 1R13).

Green. On November 18, 2009, the inspectors identified a noncited violation of

Technical Specification 3.0.4.b for ascension from Mode 4 to Mode 3 without establishing

required risk management actions. Wolf Creek used technical specification Limiting

Condition for Operation 3.0.4.b to permit mode ascension after performance of a risk

assessment and identification of risk management actions to maintain safety in the next

mode. The turbine-driven auxiliary feedwater pump was inoperable per Technical

Specification 3.7.5. As a risk management action, protected train signs would be placed

on the doors to the motor-driven auxiliary feedwater Pump A and B room doors. A

walkdown conducted by the inspector on the morning of November 18, 2009, found that

the protected train signs on the motor-driven auxiliary feedwater pump rooms were not in

place. Also, a maintenance crew was performing radiography in the motor-driven

auxiliary feedwater pump Room B. The motor-driven auxiliary feedwater Pumps A and B

were also made inoperable (at separate times) later on the morning of November 18,

2009. The licensee entered this issue in their corrective action program as Condition

Report 21926.

Mode ascension under Technical Specification LCO 3.0.4.b without establishing required

risk management actions is a performance deficiency. The finding was more than minor

because it was associated with the configuration control and alignment attribute of the

Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the

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

prevent undesirable consequences. The configuration control issues not only included

the work being completed on the turbine-driven auxiliary feedwater pump, but also

included containment isolation valve testing and radiography that was performed on the

motor-driven auxiliary feedwater pumps which was not included in the risk assessment.

The inspector used Inspection Manual Chapter 0609.04, to determine that the finding

was of very-low safety significance (Green) because it did not result in a loss of system

safety function; did not exceed allowable technical specification outage time; and was

not a seismic, flooding, or severe weather concern. Additionally, the cause of the finding

has a human performance crosscutting aspect in the area associated with decision

making. Specifically, Wolf Creek used a risk assessment form and an informal mode

change form to communicate between departments the requirement for risk

management actions. The two forms were in conflict and the personnel who

implemented the risk management actions were not informed H.1(c) (Section 1R13).

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Enclosure 2

Green. On October 15, 2009, the inspectors identified a noncited violation of 10 CFR

Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to

follow Procedure AP 28A-100, Condition Reports. Wolf Creek failed to initiate a

condition report for evaluation of corrosion on containment cooler A piping. After

inspector challenging, Wolf Creek initiated condition reports, performed nondestructive

testing, replaced corroded studs, and evaluated the cause of the corrosion.

The inspectors determined that the failure to follow AP 28A-100, Appendix C, was a

performance deficiency. This issue was more than minor because it was associated

with the equipment performance attribute of the Mitigating Systems Cornerstone and

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

systems that respond to initiating events to prevent undesirable consequences. Using

Inspection Manual Chapter 0609.04, the issue screened to Green because there was

not a loss of operability and the finding did not screen as potentially risk significant due

to a seismic, flooding, or severe weather initiating event. A crosscutting aspect was

identified in the problem identification and resolution area of the corrective action

program. Specifically, Wolf Creek failed to implement a corrective action program with a

low threshold for identifying issues P.1.a] (Section 1R13).

Green. On November 23, 2009, a self-revealing violation of Technical

Specification 5.4.1.a was identified when a technician failed to follow procedure and

emptied 45 gallons of oil from centrifugal charging Pump A rendering the pump

inoperable. The technician was supposed to remove the temperature indicator for

calibration but instead removed the thermowell which breached the lube oil subsystem

of centrifugal charging Pump A. An unplanned entry into Technical Specification 3.5.2,

Condition A, was made for approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. The licensee entered this issue in

their corrective action program as Condition Report 21993.

The failure to follow station procedures and correctly remove the detector was a

performance deficiency. The finding was more than minor because it was associated

with the equipment performance attribute of the Mitigating Systems Cornerstone and

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

systems that respond to initiating events to prevent undesirable consequences. The

inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual

Chapter 0609.04, and determined that the finding was of very low safety significance

(Green) because the pump was inoperable for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Also, the finding did

not screen as potentially risk significant due to a seismic, flooding, or severe weather

initiating event. The inspectors identified a human performance crosscutting in the area

of work practices because self-checking and communication with the supervisor failed to

prevent the event H.4.a] (Section 1R13).

Green. On November 5, 2009, inspectors identified a noncited violation of 10 CFR

Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure

to perform an adequate operability evaluation required by procedure. The inspectors

identified that Operability Evaluation EF 09-010, Revisions 0 and 1, did not demonstrate

that the essential service water pumps could withstand a safe shutdown earthquake.

Revision 2 of the operability evaluation included calculations to demonstrate acceptable

- 8 -

Enclosure 2

stresses and included pump impeller clearances. This issue is captured in the corrective

action program as condition reports 22798 and 21572.

The failure to perform an adequate operability evaluation per Procedures AP 28-001

and AP 26C 004 was a performance deficiency. The inspectors determined that this

finding was more than minor because it is associated with the equipment performance

attribute of the Mitigating Systems Cornerstone, and it affected the cornerstone objective

to ensure the availability, reliability, and capability of systems that respond to initiating

events to prevent undesirable consequences (i.e., core damage). Specifically, this issue

relates to the availability and reliability examples of the equipment performance attribute

because a latent common mode failure mechanism was not correctly evaluated. The

inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual

Chapter 0609, Appendix A, and determined that the finding was of very low safety

significance (Green) because the issue was not a design or qualification deficiency

confirmed to result in loss of operability or functionality, did not represent a loss of

system safety function, an actual loss of safety function of a single train for greater than

its technical specification allowed outage time, an actual loss of safety function of a

nontechnical specification risk-significant equipment train, and did not screen as

potentially risk significant due to a seismic, flooding, or severe weather initiating event.

The cause of the finding has a problem identification and resolution crosscutting aspect

associated with the corrective action program because Wolf Creek failed to thoroughly

evaluate the failure mechanism such that the resolutions address the causes and extent

of conditions, as necessary P.1.c] (Section 1R15).

Green. The inspectors identified a noncited violation of Technical Specification 5.4.1.a

for failure to properly implement Procedure AP 14A-003, Scaffold Construction and

Use, when scaffolding was erected against operable safety-related equipment. On

October 15, 2009, the inspectors walked down containment and identified scaffolding in

contact with component cooling water piping. The tag on the scaffold explicitly stated

that it was not seismically qualified. At the time, both steam generators were inoperable

and both trains of residual heat removal were required to be operable. The inspectors

reviewed the bases for Technical Specification 3.4.7, RCS Loops - Mode 5, Loops

Filled, which required an operable heat sink path from residual heat removal to

component cooling water to essential service water. This issue was entered into the

corrective action program as Condition Report 22464.

The construction of an unqualified scaffold against operable component cooling water

piping was a performance deficiency. The inspectors determined that this finding was

more than minor because it is associated with the equipment performance attribute for

the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the

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

prevent undesirable consequences (i.e., core damage). Specifically, this issue relates to

the availability and reliability examples of the equipment performance attribute because

a latent failure mechanism was not evaluated. The inspectors evaluated the significance

of this finding using Inspection Manual Chapter 0609, Appendix G, Attachment 1,

Shutdown Operations Significance Determination Process Phase 1 Operational

Checklists for Both PWRs and BWRs. The inspectors determined that Checklist 3 was

applicable because the unit was in cold shutdown with the refueling cavity level less than

- 9 -

Enclosure 2

23 feet. Using Appendix G, Attachment 1, Checklist 3, Phase 2 analysis was not

needed and the finding was of very low safety significance (Green) because the licensee

was able to demonstrate that the seismically unqualified scaffolding would not have

resulted in a loss of safety function. The inspectors determined the cause of the finding

had a human performance aspect in the area of resources. Specifically,

Procedure AP 14A-003 was inadequate because it had conflicting guidance that allowed

seismically unqualified scaffolds in Modes 5 and 6 H.2.c] (Section 1R20).

Cornerstone: Barrier Integrity

Green. The inspectors identified a noncited violation of Technical Specification 3.3.1,

Condition I, for making positive reactivity addition prohibited by technical specifications

in Mode 2 because one source range nuclear instrument channel was inoperable.

Following a reactor transient, one of the source range nuclear instrument channels

experienced an unanticipated increased count rate and was declared inoperable. Wolf

Creek restored the channel in an operability evaluation which cited the cause as a

problem in a component which was later determined not to exist in the installed

configuration; however, the improperly restored equipment had already been used for to

support plant startup on August 22, 2009. Wolf Creek replaced the detector during

Refueling Outage 17. This issue was entered into the correction action program as

Condition Report 20208.

Reactivity addition with source range channel Nuclear Instrument-31 inoperable is a

performance deficiency. The finding was more than minor because it was associated

with the configuration control (reactivity control) attribute of the Barrier Integrity

Cornerstone, and it affected the cornerstone objective to provide reasonable assurance

that physical design barriers (fuel cladding, reactor coolant system, and containment)

protect the public from radionuclide releases caused by accidents or events. The

inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual

Chapter 0609.04, and determined that the finding screened to Green because the

finding only affected the fuel barrier. Additionally, the cause of the finding has a human

performance crosscutting aspect in the area associated with the decision making.

Specifically, Wolf Creek did not use conservative assumptions in decision making and

adopt requirements to demonstrate that the proposed action is safe in order to proceed

rather than a requirement to demonstrate that it is unsafe in order to disapprove the

action, when performing an operability evaluation for the source range Nuclear

Instrument 31 detector prior to restarting from a forced outage H.1(b) (Section 1R15).

Green. On December 30, 2009, the inspectors identified a noncited violation of

Technical Specification Table 3.3.1-1, Function 18.a, when Wolf Creek restarted on

May 18, 2005. During a reactor shutdown on October 7, 2006, intermediate range

neutron detector Nuclear Instrument-36 did not decrease below 6E -11 amps and

energize source range detector Nuclear Instrument-32. The detector was not replaced

until Refueling Outage 16 in March 2008. The licensee entered this issue in their

corrective action program as Condition Report 22450

The inspectors determined that the failure to ensure that the P-6 interlock was operable

per the technical specification as defined in the bases was a performance deficiency.

- 10 -

Enclosure 2

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

control (reactivity control) attribute of the Barrier Integrity Cornerstone, and it affected the

cornerstone objective to provide reasonable assurance that physical design barriers (fuel

cladding, reactor coolant system, and containment) protect the public from radionuclide

releases caused by accidents or events. The inspectors evaluated the significance of

this finding using Phase 1 of Inspection Manual Chapter 0609.04, and determined that

the finding screened to Green because the P-6 interlock only affected the fuel barrier

(Section 4OA2). This finding was not assigned a crosscutting aspect because the cause

was not representative of current performance.

Cornerstone: Occupational Radiation Safety

Green. The inspector identified a noncited violation of Technical Specification 5.7.2.a.1

for failure to maintain administrative control of door and gate keys to high radiation areas

with dose rates greater than 1 rem per hour but less than 500 rads per hour (referred to

as locked high radiation areas). Specifically, as of October 21, 2009, the licensee did

not have administrative controls over a single master key to locked high radiation areas.

This issue was entered into the licensees corrective action program as Condition

Report 20973.

Failure to maintain administrative control of the master key to locked high radiation areas

was a performance deficiency. This finding is greater than minor because if left uncorrected

the finding has the potential to lead to a more significant safety concern in that an individual

could receive unanticipated radiation dose by gaining access a locked high radiation area

without the proper controls and briefing. This finding was evaluated using the occupational

radiation safety significance determination process and determined to be of very low safety

significance because it did not involve: (1) as low as is reasonably achievable planning or

work control issue, (2) an overexposure, (3) a substantial potential for overexposure, or

(4) an impaired ability to assess dose. Additionally, the violation has a crosscutting aspect

in the area of human performance associated with the work practices component because

the lack of peer and self-checking resulted in inadequate control of keys to locked high

radiation areas H.4(a) (Section 2OS1).

Cornerstone: Miscellaneous

Severity Level IV. The inspectors identified a Severity Level IV noncited violation of

10 CFR 50.73 in which the licensee failed to submit a licensee event report within 60 days

following discovery of events or conditions meeting the reportability criteria. On December

31, 2009, the inspectors identified a licensee event report that was no timely. Licensee

Event Report 2009-009-00 was not issued within 60 days for a condition prohibited by

technical specifications, and the event report did not identify that the disabling of both trains

of the P-4 interlock on August 22, 2009 was also reportable per 10 CFR 50.73(a)(2)(v). The

P-4 interlock was required by Technical Specification 3.3.2, function 8.a, and is discussed in

USAR, Section 7.3.8, NSSS Engineered Safety Feature Actuation System. Wolf Creek

licensee event report 2009-009 was correct in that the interlock is not credited in accident

analysis. However, NUREG 1022, Section 3.2.6, specifies that inoperable systems required

by the technical specifications be reported, even if there are other diverse operable means

of accomplishing the safety function.

- 11 -

Enclosure 2

The inspectors reviewed this issue in accordance with Inspection Manual Chapter 0612 and

the NRC Enforcement Manual. Through this review, the inspectors determined that

traditional enforcement was applicable to this issue because the NRC's regulatory ability

was affected. Specifically, the NRC relies on the licensee to identify and report conditions or

events meeting the criteria specified in regulations in order to perform its regulatory function,

and when this is not done, the regulatory function is impacted. The inspectors determined

that this finding was not suitable for evaluation using the significance determination process,

and as such, was evaluated in accordance with the NRC Enforcement Policy. The finding

was reviewed by NRC management, and because the violation was determined to be of

very low safety significance, was not repetitive or willful, and was entered into the corrective

action program, this violation is being treated as a Severity Level IV noncited violation

consistent with the NRC Enforcement Policy. This finding was determined to have a

crosscutting aspect in the area of problem identification and resolution associated with the

corrective action program in that the licensee failed to appropriately and thoroughly evaluate

for reportability aspects all factors and time frames associated with the inoperability of the

engineered safety features actuation system P.1(c) (Section 4OA3).

B.

Licensee-Identified Violations

Two violations of very low safety significance, which were identified by the licensee,

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

licensee have been entered into the licensees corrective action program. These

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

Section 4OA7.

- 12 -

Enclosure 2

REPORT DETAILS

Summary of Plant Status

The plant started the inspection period at 100 percent rated thermal power. On October 10,

2009, Wolf Creek shutdown for Refueling Outage 17. On November 17, 2009, Wolf Creek

achieved criticality and on November 24, 2009, Wolf Creek achieved 100 percent power and

remained there for the remainder of the inspection period.

1.

REACTOR SAFETY

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

Preparedness

1R01 Adverse Weather Protection (71111.01)

.1

Readiness to Cope with External Flooding

a.

Inspection Scope

On October 28, 2009, the inspectors evaluated the design, material condition, and

procedures for coping with the design basis probable maximum flood. The evaluation

included a review to check for deviations from the descriptions provided in the Updated

Safety Analysis Report (USAR) for features intended to mitigate the potential for

flooding from external factors. As part of this evaluation, the inspectors checked for

obstructions that could prevent draining, checked that the roofs did not contain obvious

loose items that could clog drains in the event of heavy precipitation, and determined

that barriers required to mitigate the flood were in place and operable. Additionally, the

inspectors performed a walkdown of the protected area to identify any modification to

the site that would inhibit site drainage during a probable maximum precipitation event

or allow water ingress past a barrier. The inspectors also reviewed the abnormal

operating procedure for mitigating the design basis flood to ensure it could be

implemented as written.

These activities constitute completion of one external flooding sample as defined in

Inspection Procedure IP 71111.01-05.

b.

Findings

No findings of significance were identified.

- 13 -

Enclosure 2

1R04 Equipment Alignments (71111.04)

.1

Partial Walkdown

a.

Inspection Scope

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

October 21, 2009, Train A while emergency diesel generator B and offsite power

out of service for maintenance

October 21, 2009, Spent fuel pool train A while spent fuel pool train B out of

service

The inspectors selected these systems based on their risk significance relative to the

Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted

to identify any discrepancies that could affect the function of the system, and, therefore,

potentially increase risk. The inspectors reviewed applicable operating Procedures,

system diagrams, USAR, technical specification requirements, administrative technical

specifications, outstanding work orders, condition reports, and the impact of ongoing

work activities on redundant trains of equipment in order to identify conditions that could

have rendered the systems incapable of performing their intended functions. The

inspectors also 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. Specific documents reviewed during this

inspection are listed in the attachment.

These activities constitute completion of two partial system walkdown samples as

defined in Inspection Procedure IP 71111.04-05.

b.

Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

.1

Quarterly Fire Inspection Tours

a.

Inspection Scope

The inspectors conducted fire protection walkdowns that were focused on availability,

accessibility, and the condition of firefighting equipment in the following risk-significant

plant areas:

- 14 -

Enclosure 2

October 7, 2009, Auxiliary boiler oil combustion Impact on turbine-driven auxiliary

feedwater room

October 29, 2009, Spent fuel pool Room A

October 15, 2009, All levels of containment in Mode 5

November 12, 2009, Refueling water storage tank valve house

The inspectors reviewed areas to assess if licensee personnel had implemented a fire

protection program that adequately controlled combustibles and ignition sources within

the plant; effectively maintained fire detection and suppression capability; maintained

passive fire protection features in good material condition; and had implemented

adequate compensatory measures for out of service, degraded or inoperable fire

protection equipment, systems, or features, in accordance with the licensees fire plan.

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

as documented in the plants individual plant examination of external events with later

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

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

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

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

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

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

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

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

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

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

as defined by Inspection Procedure IP 71111.05-05.

b.

Findings

.1

Failure to Correct Discolored Boric Acid Deposits

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

Appendix B, Criterion XVI, Corrective Action, for the failure to take action to stop

leakage from the base of the refueling water storage tank or evaluate the leakage and

wastage for acceptability.

Description. During the component design basis inspection in June 2007, the inspection

team noted white and brown deposits resembling boric acid at the base of the refueling

water storage tank. The licensee informed the team that past analysis had determined

these deposits were from calcium-silicate insulation which had been used for insulating

the refueling water storage tank. In 1998, the licensee had initiated Problem

Identification Request 1998-3860 to pursue the nature of the deposits and discovered

that the deposits did contain amounts of insulation, but also contained boron. The

licensee had dismissed the boron as spillage from a sampling evolution. On two

subsequent occasions after 1998, the deposits were questioned by the licensee and

- 15 -

Enclosure 2

again dismissed as insulation based on the 1998 resolution. In each of these cases the

deposits were cleaned up, and the problem identification requests written only

addressed the poor materiel condition of the area. The component design basis

inspection team questioned the previous conclusions that the deposits were insulation

material based on the strong resemblance to boric acid deposits from leakage of reactor

coolant from the refueling water storage tank. The licensee sent samples of the deposits

for offsite laboratory analysis, which confirmed that the deposits contained boron.

Subsequently, the licensee performed inspections of the carbon steel components in the

area and determined that no significant wastage had occurred and operability of the

refueling water storage tank and its surrounding components was not affected. The

inspection team documented a noncited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, for inadequate corrective actions in response to the leakage from the

refueling water storage tank, documented in NRC Inspection Report 05000482/2007006

(ADAMS ML072880678)

On November 12, 2009, the resident inspectors walked down the refueling water storage

tank valve house and again identified that the base of the refueling water storage tank

had deposits that resembled boric acid in several locations. Some deposits had

progressed up the tank bolting several inches from the floor. Initially, Wolf Creek again

maintained that the deposits were calcium silicate from insulation. The inspectors

questioned the licensee about the deposits, and laboratory testing again demonstrated

the presence of boric acid.

The inspectors reviewed the actions Wolf Creek had taken in response to NCV

05000482/2007006-03 in the component design basis inspection report. Wolf Creek had

performed a boric acid corrosion evaluation as part of Work Order 07-300734-000, which

concluded that the refueling water storage tank leak was not active, though the tank

deposits reappeared after cleanings in July 2007, August 2008, March 2009, June 2009,

and September 2009. Wolf Creek attempted to repair roof leaks in the refueling water

storage tank valve house as a source of rain water ingress, but took no action to address

the source of the boric acid in the deposits. Wolf Creek took several samples of

deposits from the base of the refueling tank. Though one sample in June 2009 did not

contain boric acid, the majority of samples, including the most recent sample from

November 2009, did contain boron, indicating that leakage from the base of the refueling

water storage tank continued to exist. The inspectors concluded that Wolf Creek had

failed to restore compliance from the noncited violation involving the failure to correct

refueling water storage tank leakage in the component design basis inspection report.

Analysis. The failure to implement corrective actions for the refueling water storage tank

leakage was a performance deficiency. Traditional enforcement does not apply since

there were no actual safety consequences or potential for impacting the NRC's

regulatory function, and the finding was not the result of any willful violation of NRC

requirements or Wolf Creek procedures. The issue was greater than minor because if

left uncorrected, the failure to correct the presence of boric acid for extended periods of

time would become a more significant-safety concern, in that, continued wastage could

impact the studs and tank operability. The finding affected the Mitigating Systems

Cornerstone, using the Phase 1 worksheets in Inspection Manual Chapter 0609.04,

"Significance Determination Process." The inspectors determined that the finding had

- 16 -

Enclosure 2

very low safety significance (Green) because it did not result in a system or component

being inoperable and it did not screen as potentially risk significant due to a seismic,

flooding, or severe weather initiating event. The inspectors identified a crosscutting

aspect in the area of human performance associated with resources. Specifically, Wolf

Creek did not maintain long-term plant safety minimizing corrective maintenance

deferrals and this long-standing equipment issue H.2(c).

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action,

requires, in part, that measures shall be established to assure that conditions adverse to

quality are promptly identified and corrected. Contrary to the above, from 1998 to

December 31, 2009, Wolf Creek did not correct the condition adverse to quality.

Specifically, Wolf Creek did not take action to correct leakage from the refueling water

storage tank. This issue and the corrective actions are being tracked in Condition

Reports 2007-02742 and 22866. Due to the licensees failure to restore compliance

from previous NCV 05000482/2007006-03 within a reasonable time after the violation

was identified, this violation is being cited as a Notice of Violation consistent with Section

VI.A of the Enforcement Policy: VIO 05000482/2009005-01, Failure to Correct

Discolored Boric Acid Deposits (EA-10-004).

.2

Control of Transient Ignition Sources

Introduction. The inspectors identified a noncited violation of Technical

Specification 5.4.1.a for an inadequate procedure for control of transient ignition sources

due to exempting the use of flapper wheels from the requirements of AP 10-101,

Control of Transient Ignition Sources.

Description. On October 21, 2009, NRC inspectors observed maintenance personnel

performing weld preparation work on essential service water piping to containment

cooler B. The inspectors observed that the ignition control barriers for the hot work were

insufficient, in that the sparks from the preparation work extended four to five feet from

the job site and there was no fire watch apparent. When the inspectors questioned the

maintenance personnel regarding the posting of a fire watch, the maintenance personnel

stated that they were using a flapper wheel and a fire watch was not required.

On December 4, 2003, the licensee modified Procedure AP-10-101, Control of

Transient Ignition Sources, such that the use of flapper wheels was exempted from the

requirements of Procedure AP10-101. The inspectors determined that the revised

procedure adversely affected the fire safety in the affected area. This was based on

recognition that the ability of the fire watch was not limited to fire identification in a timely

manner, but also on mitigation actions that an established fire watch could take in the

event of fires. These could include such actions as the ability to close doors limiting fire

exposure to adjacent areas and providing more timely fire detection capability in certain

cases. The inspectors concluded that the licensee inappropriately revised the procedure

to exempt the use of all flapper wheels without posting a fire watch. The inspectors

determined that the inadequate procedure increased the risk of fires in the plant.

Analysis. The licensee's failure to provide an adequate procedure to control transient

ignition sources was a performance deficiency and was reasonably within the ability of

- 17 -

Enclosure 2

the licensee to prevent. The inspectors concluded that this issue had a realistic

likelihood of affecting safety. Failure to properly evaluate the removal of the fire watch

posting requirements could adversely affect or degrade the ability of the licensee to

identify and report fires caused by hot work, in a timely manner. Specifically, the use of

nonconservative exemptions for requiring fire watches to be posted could affect the

ability to adequately reduce the risk of fires in the plant. This finding is more than minor

because it affected the Mitigating Systems Cornerstone attribute of Protection Against

External Factors - Fires, and adversely affected the cornerstone objective to ensure the

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

prevent undesirable consequences. The lack of a posted fire watch could adversely

affect the ability to achieve and maintain safe shutdown in the event of a severe fire in

the affected area. Inspection Manual Chapter 0609, Appendix F, Fire Protection

Significance Determination Process, could not be used to effectively evaluate the

finding in relation to defense-in-depth strategies because it had potential effects across

multiple areas and conditions. Therefore, in accordance with Inspection Manual

Chapter 0609, Appendix M, the safety significance was determined by regional

management review and concluded that the finding was of very low safety significance

(Green) since there were no combustibles in the immediate area and fire extinguishers

were readily available. The capability of other principal defense-in-depth fire protection

features were unaffected, such as the associated fire barriers, control of transient

combustibles, manual fire suppression equipment, and the fire brigade. Additionally, the

finding was not associated with a qualification deficiency, did not result in a loss of safety

function for a system, and was not risk significance due to external initiating events.

Enforcement. Technical Specification 5.4.1.a requires, in part, that written procedures

shall be established and maintained covering the applicable procedures recommended

in Regulatory Guide 1.33, Revision 2, Appendix A, February 1972. Regulatory

Guide 1.33, "Quality Assurance Program Requirements (Operation)," Revision 2,

Appendix A, Section 1.l, requires that procedures be written for plant fire protection

program. Contrary to this requirement, from December 4, 2003, until October 21, 2009,

the licensee inappropriately exempted the use of flapper wheels from the requirements

of Procedure AP 10-101, Control of Transient Ignition Sources, reducing the fire safety

of the plant. Because this issue was determined to be of very low safety significance

(Green) and was entered into the licensees corrective action program as Condition

Report AR 00020993, this violation is being treated as a noncited violation in accordance

with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2009005-02,

Control of Transient Ignition Sources.

1R06 Flood Protection Measures (71111.06)

a.

Inspection Scope

The inspectors reviewed the USAR, the flooding analysis, and plant procedures to

assess seasonal susceptibilities involving internal flooding; reviewed the USAR and

corrective action program to determine if licensee personnel identified and corrected

flooding problems; inspected underground bunkers/manholes to verify the adequacy of

sump pumps, level alarm circuits, cable splices subject to submergence, and drainage

- 18 -

Enclosure 2

for bunkers/manholes; verified that operator actions for coping with flooding can

reasonably achieve the desired outcomes; and walked down the area listed below to

verify the adequacy of equipment seals located below the flood line, floor and wall

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

level alarms, and control circuits, and temporary or removable flood barriers. Specific

documents reviewed during this inspection are listed in the attachment.

October 6, 2009, Auxiliary feedwater rooms and sump pumps

These activities constitute completion of one flood protection measures inspection

sample as defined by Inspection Procedure IP 71111.06-05.

b.

Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

.1

Annual Inspection

a.

Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry

standards, and reviewed critical operating parameters and maintenance records.

January 14, 2009, STN PE-38 on containment cooler SGN01D

The inspectors verified that performance tests were satisfactorily conducted for heat

exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the

periodic maintenance method outlined in Electric Power Research Institute

Report NP 7552, "Heat Exchanger Performance Monitoring Guidelines;" the licensee

properly utilized biofouling controls; the licensees heat exchanger inspections

adequately assessed the state of cleanliness of their tubes; and the heat exchanger was

correctly categorized under 10 CFR 50.65, Requirements for Monitoring the

Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed

during this inspection are listed in the attachment.

These activities constitute completion of one heat sink inspection sample as defined by

Inspection Procedure IP 71111.07-05.

b.

Findings

No findings of significance were identified.

- 19 -

Enclosure 2

1R08 Inservice Inspection Activities (71111.08)

.1

Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water

Reactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control

(71111.08-02.01)

a.

Inspection Scope

The inspection procedure requires review of two or three types of nondestructive

examination activities and, if performed, one to three welds on the reactor coolant

system pressure boundary. It also requires review of one or two examinations with

relevant indications (if any were found) that have been accepted by the licensee for

continued service.

The inspectors directly observed the following nondestructive examinations:

SYSTEM

WELD IDENTIFICATION

EXAMINATION

TYPE

Feedwater System

Check Valve. Root pass indication

repair. Area 5, West Bay

Drawing WIP-M-13AE05-012-A-1

WO 08-305300-049

MT

Charging Pump

Room B

Vent valve. 1974 foot elevation

auxiliary building, Room 1108

Drawing WIP-M-13BG02-006-A-1

WO 08-310289-043

PT

Safety Injection

Vent Valve. Located in safety

injection pump Room A

Drawing WIP-M-13EM01-008-A-1

WO 0-310289-077

PT

Chemical and Volume

Control System

Blowdown line coupling letdown heat

exchanger room Drawing M-13BG34

WO 06-288993-000

PT

Feedwater System

Check valve hinge pin seal weld.

2047 foot elevation, RB C loop

Drawing WOP-M-13AE04-008-A-1

WO 08-305300-013

PT

- 20 -

Enclosure 2

SYSTEM

WELD IDENTIFICATION

EXAMINATION

TYPE

Feedwater System

Check valve - flange to pipe weld

joint. 2026 elevation of Area 5

WO 08-305300-048 and -049

RT

Reactor Vessel

Closure Head

RPV meridonal welds,

ISI Number CH-101-104-B

UT

Reactor Vessel

Closure Head

RPV meridonal weld,

ISI Number CH-101-104-C

UT

High Pressure Safety

Injection

HPSI pipe to elbow weld, ISI Number

EM-03-S015-B

UT

Residual Heat

Removal

Pipe to Pipe Weld,

ISI Number EJ-04-F019

UT

Reactor Vessel

Closure Head

Reactor vessel washer and

Bushings 19-24,

Component CH-WASH 19-24

Drawing M-189-50ISI-RBB01

WO 08-311169-014

VT - 1

Safety Injection

Vent valve. Safety injection pump

Room A

Drawing WIP-M-13EM01-008-A-01

WO 08-310289-068

VT - 1

Reactor Vessel Head

Required by 10FR50.55a, ASME

Code Case N-729-1. Also IEWA-2212

VT-2 under mirror insulation

WO 08-307175-001

VT - 2

Piping Support

In containment

Component EJ-04-H002

WO 08-311169-001

VT- 3

Piping Support

In containment.

Component EM-03-C033

WO 06-288978-001

VT- 3

- 21 -

Enclosure 2

SYSTEM

WELD IDENTIFICATION

EXAMINATION

TYPE

Piping Support

In containment.

Component BG-22-H007

WO 08-311169-011

VT- 3

During the review and observation of each examination, the inspectors verified that

activities were performed in accordance with ASME Boiler and Pressure Vessel Code

requirements and applicable procedures. During the observed nondestructive

examinations identified above, three relevant indications were identified (one dye

penetrant, one radiograph, and one boric acid leak on the control rod drive mechanism

canopy seal weld). Indications identified were dispositioned in accordance with ASME

Code and approved procedures. The two weld indications were removed and

re-examined. A control rod drive mechanism canopy seal weld clamp was installed.

There were no examinations performed where relevant indications had been accepted

by the licensee for continued service. The qualifications of all nondestructive

examination technicians performing the inspections were verified to be current.

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

SYSTEM

WELD IDENTIFICATION

WELD TYPE

Reactor Coolant

Pump Seal

Water

Reactor coolant pump seal

water supply line drain.

1974 foot elevation auxiliary

building, letdown heat

exchanger room.

WO 06-288993-000.

Inlay, Gas Tungsten Arc

Welding, hand welded

High Pressure

Safety Injection

System

Vent valve. 1974 foot elevation

of auxiliary building, area 1.

WO 08-310289-077

Inlay, Gas Tungsten Arc

Welding, hand welded

Chemical and

Volume Control

System

Vent valve. Reactor water

storage tank to centrifugal

charging Pump A suction check

valve. 1974 foot elevation of

auxiliary building, area 1.

WO 08-310289-007

Inlay, Gas Tungsten Arc

Welding, hand welded

- 22 -

Enclosure 2

SYSTEM

WELD IDENTIFICATION

WELD TYPE

Essential

Service Water

System

Containment cooler B ESW

supply isolation valve (install

flanges on pipe for butterfly

valve). 2047 foot elevation in

containment, near Cooler B

duct. WO 07-299593-012.

Inlay, Gas Tungsten Arc

Welding, hand welded

Chemical and

Volume Control

System

Vent valve. Safety Injection

Pump Room B

Valves BG-V0842 and V0843.

1974 foot elevation of auxiliary

building, area 1.

WO 08-310289-043.

Inlay, Gas Tungsten Arc

Welding, hand welded

The inspectors verified, by review, that the welding procedure specifications and the

welders had been properly qualified in accordance with ASME Code,Section IX,

requirements. The inspectors also verified through record review that essential variables

for the welding process were identified, recorded in the procedure qualification record,

and formed the bases for qualification of the welding procedure specifications. Specific

documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.01 of Inspection

Procedure IP 71111.08.

b.

Findings:

A finding involving control of transient ignition sources is described in Section 1RO5.2 of

this report.

.2

Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)

a.

Inspection Scope

The inspectors witnessed the licensees performance of the required visual inspection

(VT-2) of the reactor head and pressure-retaining components above the reactor

pressure vessel head in accordance with requirement of ASME Code Case N-729-1 as

mandated by 10 CFR 50.55a effective October 10, 2008. Implementation required

ASME Code IWA-2212 VT-2 under the mirror insulation on top of the reactor head

through multiple access points. The inspectors reviewed the results of this inspection for

evidence of leaks or boron deposits at reactor pressure boundaries and related

insulation above the head. Specific documents reviewed during this inspection are listed

in the attachment.

- 23 -

Enclosure 2

These actions constitute completion of the requirements for Section 02.02 of Inspection

Procedure PI 71111.08.

b.

Findings

No findings of significance were identified.

.3

Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)

a.

Inspection Scope:

The inspectors evaluated the implementation of the licensees boric acid corrosion

control program for monitoring degradation of those systems that could be adversely

affected by boric acid corrosion. The inspection procedure required review of plant

areas that had recently received a boric acid walkdown by the licensee, through either

direct observation or record review. The inspectors reviewed the records associated with

the licensees most recent boric acid corrosion control walkdown, as specified in

Procedure STN PE-040D, "RCS Pressure Boundary Integrity Walkdown, Revision 3.

The inspectors directly observed some of those plant areas recently walked down by the

licensee. Additionally, the inspectors independently walked down piping and

components containing boric acid inside containment and the auxiliary building. The

inspection procedure also required verification that visual inspections emphasize

locations where boric acid leaks can cause degradation of safety-significant components.

The inspectors verified through record review that the boric acid corrosion control

inspection efforts were directed towards locations where boric acid leaks can cause

degradation of safety-related components.

The inspection procedure required review of one to three engineering evaluations

performed for boric acid found on reactor coolant system piping and components. For

those sources of boron leakage identified, the engineering evaluations gave assurance

that the ASME Code wall thickness limits were properly maintained. The inspection

procedure also required review of one to three corrective actions performed for evidence

of boric acid leaks identified. The inspectors confirmed that the work orders and

evaluations generated in response to boron leakage identification were consistent with

requirements of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI.

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

These actions constitute completion of the requirements for Section 02.03 of Inspection

Procedure IP 71111.08

b.

Findings

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

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

failure to identify sources of boron leakage and document them in a corrective action

document. Specifically, during a boric acid walkdown, the inspectors identified

- 24 -

Enclosure 2

11 sources of boron leakage which had not been previously identified and documented

by the licensee.

Description. On October 23, 2009, the inspectors performed a boric acid walkdown of

areas inside containment and the auxiliary building. The inspectors identified 11 sources

of leakage which had not been previously identified and documented in a corrective

action document by the licensee during the licensees boric acid walkdowns completed

on October 11, 2009. With the exception of one leak, the leaks were not active and only

had small amounts of boric acid crystals present.

The inspectors noted that those boron leakage sources which were identified during the

walkdown inside containment were described by the licensee in the completed

walkdown procedure as having no boron indication. The licensee stated that their boric

acid inspections were focused on larger amounts of boron leakage and may have been

insensitive to smaller amounts of leakage. This is contrary to station

Procedure AP 16F-001, "Boric Acid Corrosion Control Program," Revision 5, step 6.4.1,

which states that: Sources of boron seepage/leakage shall be identified/verified and

documented in the applicable corrective action document. The licensee entered the

missed leakage sources into their corrective action program and initiated a condition

report to follow up on the extent of condition of missed boron leakage sources.

Analysis. The inspectors determined that the failure to identify sources of boron leakage

was contrary to station procedures and was a performance deficiency. Specifically,

11 examples of boron leakage were not identified and documented in a corrective action

document.

The finding was determined to be more than minor in accordance with Inspection

Manual Chapter 0612, Appendix B, Issue Screening, because it was associated with

the human performance attribute of the Initiating Events Cornerstone and affected the

cornerstone objective of limiting the likelihood of those events that upset plant stability

and challenge critical safety functions during shutdown as well as power operations.

Specifically, boric acid leakage has historically been found to degrade carbon steel

components which could affect the reactor coolant system pressure boundary or impact

the reliability of emergency core cooling systems. The inspectors used Inspection

Manual Chapter 0609, Significance Determination Process, Attachment 4, Phase 1 -

Initial Screening and Characterization of Findings, and determined the finding was of

very low safety significance (Green) because the issue would not result in exceeding the

technical specification limit for identified reactor coolant system leakage or effect other

mitigating systems resulting in a total loss of their safety function. The inspectors also

determined that the finding had a crosscutting aspect in the area of problem

identification and resolution, operating experience, where the licensee did not

institutionalizes operating experience through changes to station processes, procedures,

equipment, and training programs [P.2.(b)].

Enforcement. Title 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

- 25 -

Enclosure 2

circumstances and shall be accomplished in accordance with these instructions,

procedures, or drawings. Licensee Procedure AP 16F-001,"Boric Acid Corrosion

Control Program," Revision 5, which prescribes activities affecting quality, states, in part,

that sources of boron seepage/leakage shall be identified/verified and documented in

the applicable corrective action document. Contrary to the above, prior to October 23,

2009, the licensee failed to accomplish the requirements of Procedure AP 16F-001.

Specifically, the licensee failed to identify 11 sources of boron leakage in the containment

structure and the auxiliary building and document them in a corrective action document.

Because this issue was determined to be of very low safety significance (Green) and

was entered into the licensees corrective action program as Condition

Report AR-00021274, this violation is being treated as a noncited violation in accordance

with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2009005-03,

Failure to Identify Sources of Boron Leakage.

.4

Steam Generator Tube Inspection Activities (71111.08-02.04)

a.

Inspection Scope:

The inspection procedure specified performance of an assessment of in situ screening

criteria to assure consistency between assumed nondestructive examination flaw sizing

accuracy and data from the EPRI examination technique specification sheets. It further

specified assessment of appropriateness of tubes selected for in situ pressure testing,

observation of in situ pressure testing, and review of in situ pressure test results.

At the time of this inspection, no conditions had been identified that warranted in situ

pressure testing. The inspectors reviewed the Licensees Report SG-CDME-08-15,

Wolf Creek Refueling 16 Condition Monitoring Assessment and Operational

Assessment, Revision 1, dated April 2008, and compared the in situ test screening

parameters to the guidelines contained in the EPRI document In Situ Pressure Test

Guidelines, Revision 2. This review determined that the remaining screening

parameters were consistent with the EPRI guidelines.

In addition, the inspectors reviewed both the licensee site-validated and qualified

acquisition and analysis technique sheets used during this refueling outage and the

qualifying EPRI examination technique specification sheets to verify that the essential

variables regarding flaw sizing accuracy, tubing, equipment, technique, and analysis had

been identified and qualified through demonstration. The inspector-reviewed acquisition

technique and analysis technique sheets are identified in the attachment.

The inspection procedure specified comparing the estimated size and number of tube

flaws detected during the current outage against the previous outage operational

assessment predictions to assess the licensees prediction capability. The inspectors

compared the previous outage operational assessment predictions contained in

Report SG-CDME-08-15, Revision 1, with the flaws identified thus far during the current

steam generator tube inspection effort. Compared to the projected damage

mechanisms identified by the licensee, the number of identified indications fell within the

range of prediction and was quite consistent with predictions.

- 26 -

Enclosure 2

The inspection procedure specified confirmation that the steam generator tube test

scope and expansion criteria meet technical specification requirements, EPRI

guidelines, and commitments made to the NRC. The inspectors evaluated the

recommended steam generator tube eddy current test scope established by technical

specification requirements. The inspectors compared the recommended test scope to

the actual test scope and found that the licensee had accounted for all known flaws and

had established a test scope that met or exceeded minimum technical specification

requirements, EPRI guidelines, and commitments made to the NRC. The scope of the

licensees Eddy current examinations of tubes in both steam generators included:

100 percent, bobbin examination of tubes in steam generators A and D, full length

except for rows 1 and 2, which were inspected with the bobbin from tube end to tube

support plate 7 from both hot and cold legs

50 percent, Rows 1 and 2 U-bends, mid-range +Point examination in steam

generators A and D

Mid-range +Point examination of 100 percent of the cold leg peripheral tubes in steam

generators A and D

Dings (free span) > 5 volts: inspect 50 percent of all previously identified and new dings

>5 volts in the hot leg (including the U-bends) with the mid-range +Point probe in steam

generators A and D

Dents (structures) > 2 volts: inspect 50 percent of all previously identified and new dents

>2 volts in the hot leg (including the U-bends) with the mid-range +Point probe in steam

generators A and D

+Point examination of all "I-code" indications that were not resolved after history review

+Point inspection of new wear indications and prior wear indications that have changed

by 10 percent through-wall defect or greater in steam generators A and D

Visual inspection of mechanical and weld plugs

+Point examination of a five percent sample of bobbin indications that have not changed

since the prior inspection (H and S codes)

+Point inspection to bound (all surrounding tubes, at least one pitch removed) the tubes

exhibiting possible loose parts signals during the inspection

+Point inspection of a sample of tubes to support the scale profiling effort

The results, as known to the inspectors at the conclusion of this inspection, are as

follows:

For steam generator A, 6 tubes with wear indication of 40 percent through-wall defect or

greater at one or more anti-vibration bar intersections were plugged. Additionally, one

tube was conservatively plugged for a geometric anomaly. This tube did not exhibit any

cracking characteristic after analysis of the +Point and Ghent probe data.

- 27 -

Enclosure 2

For steam generator D, 10 tubes with wear indication of 40 percent through-wall defect

or greater at one or more anti-vibration bar intersections were plugged. Additionally, one

tube was conservatively plugged for a geometric anomaly. This tube did not exhibit any

cracking characteristic after analysis of the +Point and Ghent probe data.

The inspection procedure specified that, if new degradation mechanisms were identified,

the licensee would verify the analysis fully enveloped the problem of the extended

conditions including operating concerns and that appropriate corrective actions were

taken before plant startup. No new degradation mechanisms were identified by the

eddy current examination results.

The inspection procedure required confirmation that the licensee inspected all areas of

potential degradation, especially areas that were known to represent potential eddy

current test challenges (e.g., top of tube sheet, tube support plates, and U-bends). The

inspectors confirmed that all known areas of potential degradation were included in the

scope of inspection and were being inspected.

The inspection procedure further required verification that repair processes being used

were approved in the technical specifications. At the completion of the inspection, the

inspectors were informed that 18 tubes were to be plugged. The inspectors verified that

the mechanical expansion plugging process used was an NRC-approved repair process.

The inspection procedure also required confirmation of adherence to the technical

specification plugging limit, unless alternate repair criteria had been approved. The

inspection procedure further requires determination whether depth sizing repair criteria

were being applied for indications other than wear or axial primary water stress corrosion

cracking in dented tube support plate intersections. The inspectors determined that the

technical specification plugging limits were being adhered to (i.e., 40 percent maximum

through-wall indication).

If steam generator leakage greater than three gallons per day was identified during

operations or during post shutdown visual inspections of the tube sheet face, the

inspection procedure required verification that the licensee had identified a reasonable

cause based on inspection results and that corrective actions were taken or planned to

address the cause for the leakage. The inspectors did not conduct any assessment

because this condition did not exist.

The inspection procedure required confirmation that the eddy current test probes and

equipment were qualified for the expected types of tube degradation and an assessment

of the site-specific qualification of one or more techniques. The inspectors observed

portions of eddy current tests performed on the tubes in steam generators A and D.

During these examinations, the inspectors verified that: (1) the probes appropriate for

identifying the expected types of indications were being used, (2) probe position location

verification was performed, (3) calibration requirements were adhered to, and (4) probe

travel speed was in accordance with procedural requirements. The inspectors

performed a review of site-specific qualifications of the techniques being used. These

are identified in the attachment.

- 28 -

Enclosure 2

The inspection procedure specified that if loose parts or foreign materials were identified

on the secondary side, the inspectors should review the licensee's evaluation of the

materials and/or complete appropriate repairs of affected steam generator tubes.

Additionally, the licensee should either remove accessible foreign objects or perform an

evaluation of the potential effects of inaccessible object migration and tube fretting

damage. During this inspection, 18 small foreign objects were found in steam

generator A; of these, 7 items were retrieved. There were 34 small foreign objects found

in steam generator D; of these, 18 items were retrieved. These objects, small wires and

sludge rocks, were prioritized and retrieved based on their potential to damage the

steam generator tubes in accordance with Refuel Outage 17 Degradation Assessment

and EPRI 1019039, Steam Generator Management Program: Foreign Object

Prioritization Strategy for Square Pitch Steam Generators. Those items not removed

from the steam generators were evaluated and determined to have no ability to damage

the steam generator tubes during operation. Condition Report AR-00021178 documents

the foreign objects in the licensee's corrective action program. The required chemical

and mechanical effects of these remaining pieces were analyzed with the conclusion of

negligible effects on the respective steam generators. Work Orders 09-321481-000 and

09-321386-000 evaluated the acceptability of the steam generators with these minor

foreign objects remaining.

Finally, the inspection procedure specified review of one-to-five samples of eddy current

test data if questions arose regarding the adequacy of eddy current test data analyses.

The inspectors did not identify any results where eddy current test data analyses

adequacy was questionable.

These actions constitute completion of the requirements for Section 02.04 of Inspection

Procedure IP 71111.08.

b.

Findings

No findings of significance were identified.

.5

Identification and Resolution of Problems (71111.08-02.05)

a.

Inspection Scope

The inspection procedure required review of a sample of problems associated with

inservice inspections documented by the licensee in the corrective action program for

appropriateness of the corrective actions.

The inspectors reviewed nine condition reports which dealt with inservice inspection

activities and found the corrective actions were appropriate. The specific condition

reports reviewed are listed in the documents reviewed section. From this review, the

inspectors concluded that the licensee has an appropriate threshold for entering issues

into the corrective action program and has procedures that direct a root cause evaluation

when necessary. The licensee also has an effective program for applying industry

- 29 -

Enclosure 2

operating experience. Specific documents reviewed during this inspection are listed in

the attachment.

These actions constitute completion of the requirements for Section 02.05 of Inspection

Procedure IP 71111.08.

b.

Findings:

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)

a.

Inspection Scope

There were no opportunities to inspect operator requalification in the fourth quarter.

There were zero activities completed for quarterly licensed-operator requalification as

defined in Inspection Procedure IP 71111.11.

b.

Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a.

Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk

significant systems:

October 27, 2009, 125Vdc nonsafety-related PK system

December 17, 2009, Component cooling water system

December 18, 2009, Source range neutron monitors

October 6, 2009, Residual heat removal system

December 21, 2009, Offsite power supplies

December 22, 2009, Intermediate range neutron monitors

The inspectors reviewed events such as where ineffective equipment maintenance has

resulted in valid or invalid automatic actuations of engineered safeguards systems and

independently verified the licensee's actions to address system performance or condition

problems in terms of the following:

Implementing appropriate work practices

Identifying and addressing common cause failures

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

- 30 -

Enclosure 2

Characterizing system reliability issues for performance

Charging unavailability for performance

Trending key parameters for condition monitoring

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

Verifying appropriate performance criteria for structures, systems, and

components classified as having an adequate demonstration of performance

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

requiring the establishment of appropriate and adequate goals and corrective

actions for systems classified as not having adequate performance, as described

in 10 CFR 50.65(a)(1)

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

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

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

significance characterization. Specific documents reviewed during this inspection are

listed in the attachment.

These activities constitute completion of six quarterly maintenance effectiveness

samples as defined in Inspection Procedure IP 71111.12-05.

b.

Findings

No findings of significance were identified.

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

a.

Inspection Scope

The inspectors reviewed licensee personnel's evaluation and management of plant risk

for the maintenance and emergent work activities affecting risk-significant and safety-

related equipment listed below to verify that the appropriate risk assessments were

performed prior to removing equipment for work:

November 20, 2009, Emergent work on control room door ventilation boundary

October 15, 2009, Corrosion on containment cooler A

October 13, 2009, Emergent work on annunciator power supply failures

October 10 to November 17, 2009, Shutdown risk assessments

November 18, 2009, Technical Specification 3.0.4.b risk assessment for Mode 4

to Mode 3

November 23, 2009, Emergent work for oil loss from centrifugal charging pump A

- 31 -

Enclosure 2

The inspectors selected these activities based on potential risk significance relative to

the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified

that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)

and that the assessments were accurate and complete. When licensee personnel

performed emergent work, the inspectors verified that the licensee personnel promptly

assessed and managed plant risk. The inspectors reviewed the scope of maintenance

work, discussed the results of the assessment with the licensee's probabilistic risk

analyst or shift technical advisor, and verified plant conditions were consistent with the

risk assessment. The inspectors also reviewed the technical specification requirements

and inspected portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met. Specific

documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three maintenance risk assessments and

emergent work control inspection sample as defined by Inspection

Procedure IP 71111.13-05.

b.

Findings

.1

Introduction. The inspectors identified a Green noncited violation of 10 CFR 50.65(a)(4)

involving the failure to adequately perform shutdown risk assessments during Refueling

Outage 17.

Description. While reviewing daily risk assessments during Refueling Outage 17, the

inspectors noted discrepancies in the calculation of the risk conditions of the shutdown

safety function condition. As a result, the inspectors reviewed the AP 22B-001, Outage

Risk Assessment, and Form APF 22B-001-02, Daily Shutdown Risk Assessment.

Wolf Creek uses Procedure AP 22B-001, to implement the requirements of 10

CFR 50.65(a)(4) during shutdown conditions (Modes 4, 5, 6, and defueled). In the

references section, the procedure lists NUMARC 93-01, Section 11, Assessment of

Risk Resulting from Performance of Activities, as well as Regulatory Guide 1.182 in

which the NRC endorses NUMARC 93-01, Section 11, dated February 2000. Wolf

Creek has no NRC approved exceptions to Regulatory Guide 1.182. NUMARC 93-01,

Section 11.3.5, provides a scope of five key Shutdown Safety Functions: decay heat

removal capability, inventory control, electric power availability, reactivity control, and

containment. Sections 11.3.6.1 through 11.3.6.5 provide specifics for each shutdown

function. Overall, the inspectors found several examples in which the five aspects

NUMARC 93-01, Section 11, were not correctly implemented for risk assessments.

Form APF 22B-001-02 defines Condition 3 or High Risk as only one safety train is

available to satisfy the shutdown safety function. In the examples below, this

contradicted with Wolf Creeks actions.

For the Decay Heat Removal Shutdown Safety Function, Procedure APF 22B-001-02

did not direct consideration of containment closure time per NUMARC 93-01,

Section 11.3.6.1. The inspectors cross-referenced the daily shutdown risk assessment

forms with the equipment out-of-service list maintained in the control room log and found

three such instances of this occurring. First, on October 16 and 17, 2009, during the

- 32 -

Enclosure 2

core offload, the reactor building equipment hatch was listed as closed during fuel

movement; however, the equipment out-of-service list showed the equipment hatch as

open from October 10 through November 15, 2009. Secondly, from October 14-17,

2009, and again on November 5-11, 2009, the reactor building auxiliary access hatch

was on the equipment out-of-service list because the interlocks were defeated to install

a temporary closure device. The daily risk assessment did not analyze this condition

which had the potential to impact the outcome of the risk assessment. The third

instance occurred on November 16, 2009, when the reactor building personnel hatch

failed to meet the surveillance requirement acceptance criteria. This was also not

analyzed for its effect on containment closure.

For the (Electric) Power Availability Shutdown Safety Function,

Procedure APF 22B-001-02 did not explicitly direct consideration of ac and dc

instrumentation and control power availability per NUMARC 93-01, Section 11.3.6.3.

The inspectors cross-referenced the daily shutdown risk assessment forms with the

equipment out-of-service list maintained in the control room log archive and found two

such instances of this occurring. First from October 19 through 25, 2009, the 125Vdc

60-Cell Battery 4 was inoperable pending further analysis due to positive plate material

separation identified during a visual inspection. The corresponding NK04 electrical bus

was incorrectly considered available on the six daily risk assessments performed during

that time period. The second instance occurred on November 6 through 10, 2009, when

the 125Vdc 60-Cell Battery 3 inoperable pending further analysis due to several cell

abnormalities identified during a visual inspection. The corresponding NK03 electrical

bus was incorrectly considered available on the five daily risk assessments performed

during that time period. Furthermore, these dc power unavailabilities were listed on the

risk assessment, but were not factored into its outcome (or color).

For the Containment Shutdown Safety Function, Procedure APF 22B-001-02 did not

direct consideration of the availability of ventilation and radiation monitoring equipment

with respect to the filtration and monitoring of releases per NUMARC 93-01,

Section 11.3.6.5. The inspectors again cross-referenced the daily shutdown risk

assessment forms with the equipment out-of-service list maintained in the control room

log and identified two such instances of this occurring. The first instance occurred

during core offload on October 17, 2009. At that time, the availability of Containment

Atmospheric Radiation Monitor GTRE0031 was degraded because it was being powered

by temporary power. The normal source, safety bus NB02, was de-energized for

maintenance from October 17 through 25, 2009. The second instance occurred during

core reload on November 5 and 6, 2009, when the GTRE0021B was removed from

service from October 29 through November 28, 2009, per the equipment out-of-service

list. Neither of these components was listed in the daily risk assessment, nor was their

impact quantified in the determination of the risk level (or color).

For the Decay Heat Removal Shutdown Safety Function, only residual heat removal

and steam generators can actually perform the function of heat removal. The risk

assessments credited reactor cavity level greater than 23 feet above the vessel flange

and a greater than 4-hour time to boil in the decay heat removal function. Thus, this

configuration would be a permissible, moderate risk condition even if there were no

active means of removing heat from the reactor. The inspectors cross-referenced the

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Enclosure 2

daily shutdown risk assessment forms with the equipment out-of-service list and

identified two instances of this occurring. First, on October 10, 2009 at 10:29 a.m., and

again on November 13 through 17, 2009, the risk assessments specified that steam

generators were available for heat removal when the auxiliary feedwater system was

unavailable because its safety-related water source (essential service water) was

isolated by Clearance Order C17-R-OP-S-005. Steam generators were available for

reflux cooling. Wolf Creek credits reflux cooling using EPRI Technical Report 102972,

Reflux Cooling: Application to Decay Heat Removal During Shutdown Operations.

The earliest EPRI analyzed scenario is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after shutdown; however, on

October 10, 2009, only 10.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following shutdown, the decay heat load would be

significantly higher and warrant further analysis. The inspectors concluded that since

this condition was unanalyzed, it could not be credited and a steam generator feedwater

source would be required for such a short time after reactor shutdown. The decay heat

removal Shutdown Safety Function was categorized as normal risk (green) when it

should have been moderate risk (yellow) for the two risk assessments performed on

October 10, 2009. The other risk assessments that use reflux cooling were bounded by

the EPRI analysis. Lastly, the inspectors reviewed spent fuel pool cooling on

October 30, 2009. The risk assessment form specified one train was available and

resulted in moderate risk (yellow); however, red risk was defined as one safety train

available for the function. Although not an input to the color, the form specified normal

and alternate makeup water sources to the spent fuel pool. Inspectors interviewed

senior operators to identify the normal and alternate sources. One indicated that the

refueling water storage tank through the spent fuel pool transfer pumps was the normal

source. Another indicated demineralized water was the makeup source. For the

alternate makeup source, one indicated essential service water while another stated it

was fire water. In any case, none of the sources were specified and tracked by the risk

assessment form to mitigate the loss of one fuel pool cooling train.

For the [Electric] Power Availability Shutdown Safety Function, a loss of offsite power,

or loss of both diesel generators, combined with no switchyard activities is categorized

as a low risk condition. Furthermore, a station blackout with no switchyard activities in

progress is a moderate risk condition. Inspectors found that this resulted in an

inadequate risk assessment for electrical power in that the risk assessment would permit

shutdown activities without any available sources of ac power. Wolf Creek categorized

one in-service power source as moderate risk (yellow) rather than high risk. This was in

contrast to the definition of high risk in which only one safety train available to satisfy the

function. The inspectors cross-referenced the daily shutdown risk assessment forms

with the equipment out-of-service list maintained in the control room log and found that

on November 8, 2009, at 8:57 a.m. the risk assessment listed two diesel generators as

being available; however, the equipment out-of-service list indicated that emergency

diesel generator A was out of service because essential service water train A was

unavailable from November 5, 2009, at 4:37 a.m. until November 8, 2009, at 1:30 p.m.

When the credit for emergency diesel generator A is removed, the risk assessment

outcome changes from normal risk (green) to moderate risk (yellow). The second

instance occurred for the daily risk assessment performed between October 31 and

November 4, 2009, which lists two diesel generators as being available. However, the

equipment out-of-service list indicated that emergency diesel generator B was out of

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Enclosure 2

service because essential service water Train B was unavailable from October 16, 2009,

at 10:05 p.m. until November 5, 2009, at 4:19 a.m. On all five daily risk assessments

performed between October 31 and November 4, 2009, if the credit for the second diesel

generator were removed, the outcome of the risk assessment changed from normal risk

to moderate risk.

Analysis. The failure to meet shutdown risk assessment requirements in the shutdown

risk assessment process is a performance deficiency. Traditional enforcement does not

apply since there were no actual safety consequences or potential for impacting the

NRC's regulatory function, and the finding was not the result of any willful violation of

NRC requirements or Wolf Creek procedures. The inspectors determined that this

finding impacted the Mitigating Systems Cornerstone and was more than minor because

it involved incorrect risk assessments that changed the outcome or color of the

assessments. Per Inspection Manual Chapter 0609, Appendix K, Maintenance Risk

Assessment and Risk Management Significance Determination Process, licensees who

only perform qualitative analyses of plant configuration risk due to maintenance

activities, the significance of the deficiencies must be determined by an internal NRC

management review using risk insights where possible in accordance with Inspection

Manual Chapter 612, Power Reactor Inspection Reports. The NRC management

review concluded that this finding was of Green safety significance because missing risk

management actions did not result in loss of key shutdown risk functions. Additionally,

the cause of the finding has a human performance crosscutting aspect in the area

associated with the resources. Specifically, Wolf Creek did not ensure that

Procedure APF 22B-001-02 was complete, accurate, and up-to-date H.2(c).

Enforcement. Title 10 CFR 50.65(a)(4) states, in part, that before performing

maintenance activities (including but not limited to surveillance, postmaintenance testing,

and corrective and preventive maintenance), the licensee shall assess and manage the

increase in risk that may result from the proposed maintenance activities. Contrary to

the above, between October 10, and November 17, 2009, Wolf Creek did not

appropriately assess and manage the increase in risk resulting from proposed

maintenance activities. Specifically, Form APF 22B-001-02 did not appropriately

consider electrical power, decay heat removal, and containment when assessing

shutdown risk. Because the finding is of very low safety significance and has been

entered into the corrective action program as condition reports 22295 and 22296, this

violation is being treated as a noncited violation, consistent with Section VI.A of the NRC

Enforcement Policy: NCV 05000482/2009005-04, Failure to Incorporate Requirements

of Regulatory Guide 1.182 into Daily Shutdown Risk Assessments.

.2

Introduction. On November 18, 2009, the inspectors identified a Green noncited

violation of Technical Specification 3.0.4.b for ascension from Mode 4 to Mode 3 without

establishing required risk management actions.

Description. On the morning of November 18, 2009, the turbine-driven auxiliary

feedwater pump was inoperable per technical specification 3.0.4.b as specified in the

control room log at 11:53 p.m. the previous day upon ascension from Mode 4 into

Mode 3 at 12:24 a.m. Technical specification 3.0.4.b permits mode ascension after

performance of a risk assessment to address the inoperable components and

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Enclosure 2

consideration and implementation of risk management actions to maintain safety in the

next mode. This condition is permissible for auxiliary feedwater per Technical

Specification LCO 3.7.5 so long as the ascension is below Mode 1. The entry was made

using an operational risk assessment Form APF 22C-003-01 in accordance with

Technical Specification LCO 3.0.4.b. The risk assessment on November 17, 2009,

specified:

1.

The turbine-driven auxiliary feedwater pump restoration following Surveillance

Requirement 3.7.5.2, completion is expected within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of entering Mode 3.

2.

As a compensatory measure [risk management action], protected train signs

would be placed on the doors to the motor-driven auxiliary feedwater pumps A

and B room doors.

A walkdown conducted by the inspector at 10:30 a.m. on November 18, 2009, found that

the protected train signs on the motor-driven auxiliary feedwater pump rooms specified

by the operational risk assessment were not in place. Also, a maintenance crew was

performing radiography in the motor-driven auxiliary feedwater pump Room B. A further

review of the control room logs revealed that motor-driven auxiliary feedwater pump

comprehensive pump testing, flow path verification, and containment isolation valve

verification testing were scheduled and performed, making both motor-driven auxiliary

feedwater pumps A and B inoperable (at separate times) during the morning of

November 18, 2009, while turbine-driven auxiliary feedwater was still inoperable.

Operators did make proper entry into Technical Specification 3.7.5, Condition C, for two

of three auxiliary feedwater trains inoperable; however, this configuration was not

analyzed in the risk assessment. Immediately following the walkdown, the inspector

discussed the issue with the shift manager, the protected train signs were installed on

the motor-driven auxiliary feedwater pump room doors and a condition report was

initiated. Wolf Creek determined that an informal mode ascension check off list was

used that conflicted with the risk assessment performed for Technical

Specification 3.0.4.b.

Analysis. Mode ascension under Technical Specification LCO 3.0.4.b without

establishing required risk management actions is a performance deficiency. Traditional

enforcement does not apply since there were no actual safety consequences or potential

for impacting the NRC's regulatory function, and the finding was not the result of any

willful violation of NRC requirements or Wolf Creek procedures. The inspectors

determined that the violation was more than minor because it was associated with the

configuration control and alignment attribute of the Mitigating Systems Cornerstone and

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

systems that respond to initiating events to prevent undesirable consequences. The

configuration control issues not only included the work being completed on the

turbine-driven auxiliary feedwater pump, but also included containment isolation valve

testing and radiography that was performed on the motor-driven auxiliary feedwater

pumps which was not included in the risk assessment. The inspector used Inspection

Manual Chapter 0609.04, Phase 1 SDP - Worksheet, to determine that the finding was

of very low safety significance (Green) because it did not result in a loss of system safety

function; exceed allowable technical specification outage time; and was not a seismic,

- 36 -

Enclosure 2

flooding, or severe weather concern. Additionally, the cause of the finding has a human

performance crosscutting aspect in the area associated with the decision making.

Specifically, Wolf Creek used a risk assessment form and informal mode change form to

communicate between departments the requirement for risk management actions. The

two forms were in conflict, and the personnel who implemented the risk management

actions were not informed H.1(c).

Enforcement. Wolf Creek Technical Specification LCO 3.0.4.b states, in part, When an

LCO is not met, entry into a MODE or other specified condition in the Applicability shall

only be made after performance of a risk assessment addressing inoperable systems

and components, consideration of the results, determination of the acceptability of

entering the MODE or other specified condition in the Applicability, and establishment of

risk management actions, if appropriate. Prior to MODE ascension with the

turbine-driven auxiliary feedwater pump inoperable, Wolf Creek performed a risk

assessment and identified risk management actions. Contrary to the above, on

November 18, 2009, at 12:24 a.m. Wolf Creek invoked Technical Specification 3.0.4.b to

ascend from Mode 4 to Mode 3 without implementing the risk management actions

required by the risk assessment performed to justify the Mode change with the

turbine-driven auxiliary feedwater pump inoperable. Because the finding is of very low

safety significance and has been entered into the corrective action program as Condition

Report 00021926, this violation is being treated as a noncited violation, consistent with

Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-05, Mode

Change under Technical Specification 3.0.4.b Without Required Risk Management

Actions.

.3

Introduction. On October 15, 2009, the inspectors identified a violation of 10 CFR

Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to

follow Procedure AP 28A-100, Condition Reports. Wolf Creek failed to initiate a

condition report for evaluation of corrosion on containment cooler A piping.

Description. On October 15, 2009, the inspectors identified dried white and brown

deposits on vertical piping from insulation seams on containment cooler A. The

inspectors identified the condition to Wolf Creek. On October 17, Wolf Creek completed

Work Order 09-321113-000 to remove the insulation and found significant corrosion of

piping and flanges for containment cooler A. Work Order 09-321113-000 stated that the

cause of the corrosion was unknown. Wolf Creek informed the inspectors that the cause

of the corrosion was condensation. The inspectors noted that since no ultrasonic testing

had been performed, leakage from through-wall defects could not be eliminated as a

cause. Wolf Creek later informed the inspectors that the visual inspection showed no

through wall defects. The inspectors again challenged Wolf Creek since no ultrasonic

testing was performed to demonstrate that through wall defects could be eliminated as a

cause. The inspectors reviewed Procedure AP 28A-100, Condition Reports,

Revision 10, Attachment C. Attachment C required condition reports when equipment

issues require evaluation beyond the work controls (work order) process.

Procedure AP 28A-100 defines an adverse condition as one that could impact nuclear

safety. Wolf Creek subsequently initiated Condition Report 20964 on October 21, 2009,

stating that there was extensive corrosion on containment cooler A and that all

containment coolers could be affected. Condition Report 20964 went on to evaluate the

- 37 -

Enclosure 2

piping insulation and how it did not prevent condensation on the piping which allowed

the corrosion.

On October 23 and October 26, Wolf Creek initiated several work requests to perform

ultrasonic testing of containment coolers A, B, and C. Wolf Creek initiated the work

order to perform piping and flange thickness measurements which were found to be

satisfactory. Wolf Creek engineering determined that containment coolers A, B, and C

had piping flange studs that needed to be replaced due to corrosion. From November 1

to November 2, a total of 32 studs and 96 nuts were replaced for the three coolers. On

November 8 and 11, 2009, Wolf Creek completed engineering dispositions to address

the cause and the results of the ultrasonic testing. Condition Report 22443 also

identified the need for more ultrasonic inspections in the next refueling outage to verify

acceptable corrosion rates. On December 16, 2009, Wolf Creek initiated Condition

Report 22443 which described the lack of a timely condition report to determine a cause

of the corrosion.

Analysis. The inspectors determined that the failure to follow Procedure AP 28A-100,

Appendix C, was a performance deficiency. Traditional enforcement does not apply

since there were no actual safety consequences or potential for impacting the NRCs

regulatory function, and the finding was not the result of any willful violation of NRC

requirements or Wolf Creek procedures. This issue was more than minor because it

was associated with the equipment performance attribute of the Mitigating Systems

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

and capability of systems that respond to initiating events to prevent undesirable

consequences. Using Inspection Manual Chapter 0609.04, the issue screened to Green

because there was not a loss of operability and the finding did not screen as potentially

risk significant due to a seismic, flooding, or severe weather initiating event. A

crosscutting aspect was identified in the problem identification and resolution area of the

corrective action program. Specifically, Wolf Creek failed to implement a corrective

action program with a low threshold for identifying issues P.1.a].

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

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

documented instructions, procedures or drawings appropriate to the circumstances and

be accomplished in accordance with these instructions, procedures or drawings.

Procedure AP 28A-100, Attachment C, Equipment Problems Requiring a Condition

Report, requires, in part, that condition reports be written where further evaluation is

needed outside the work control process. Contrary to the above, from October 15 to 23,

2009, Wolf Creek failed to complete an activity affecting quality in accordance with

documented procedures appropriate to the circumstances. Specifically, Wolf Creek

failed to write a condition report for corrosion on containment cooler A after Work

Order 09-321113-000 stated that the cause of the corrosion was unknown. Because this

violation was determined to be of very low safety significance and was placed in the

corrective action program as Condition Reports 20964 and 22443, this violation is being

treated as a noncited violation in accordance with Section VI.A.1 of the Enforcement

Policy: NCV 05000482/2009005-06, Failure to Follow Corrective Action Procedure.

- 38 -

Enclosure 2

.4

Introduction. On November 23, 2009, a self-revealing violation of Technical

Specification 5.4.1.a was reviewed by the inspectors after a technician failed to follow

procedures and emptied 45 gallons of oil from centrifugal charging pump A.

Description. On November, 23, 2009, a technician loosened the wrong nut and removed

the thermowell for Temperature Indicator BG TI-0036 on centrifugal charging pump A. At

the time, the auxiliary lube oil pump was running. The auxiliary lube oil pump normally

runs while the pump is in standby. This emptied 45 gallons of oil from the pump.

Removal of the temperature indicator normally would not affect operability since the oil

temperature indication is not required; however, the pump cannot function without lube

oil. Control room operators declared the pump inoperable and entered Technical

Specification 3.5.2. Approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> later, the thermowell and oil were replaced,

the pump was leak tested and Technical Specification 3.5.2, Condition A was exited.

Wolf Creek performed a root cause analysis for this issue under Condition

Report 21993. During interviews, the technician stated that he performed a 2 minute

self-check (a recognized error reduction technique at Wolf Creek) but failed to identify

the correct nut to loosen. This task is a required training task for these temperature

indicators, which involves a similar training rig. The technician stated that he understood

the difference between the thermowell nut and the temperature indicator but failed to

make the differentiation on November 23. The technician and the supervisor discussed

the work, but the communication was inadequate because the technician was left with

the idea to perform the work independently, and the supervisor believed that the

technician was only going to perform a walkdown of the indicator. The prejob briefing

standard at Wolf Creek required supervisor approval for a self-briefing.

Analysis. The failure to follow Procedure STN IC-294A and correctly remove the

detector was considered a performance deficiency. Traditional enforcement does not

apply since there were no actual safety consequences or potential for impacting the

NRC's regulatory function, and the finding was not the result of any willful violation of

NRC requirements or Wolf Creek procedures. The finding was more than minor

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

Systems Cornerstone, and it affected the cornerstone objective to ensure the availability,

reliability, and capability of systems that respond to initiating events to prevent

undesirable consequences. The inspectors evaluated the significance of this finding

using Phase 1 of Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and

Characterization of Findings, and determined that the finding was of very low safety

significance (Green) because the pump was inoperable for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Also, the

finding did not screen as potentially risk significant due to a seismic, flooding, or severe

weather initiating event. The inspectors identified a human performance crosscutting in

the area of work practices because a 2-minute self-check and communication with the

supervisor failed to prevent the event H.4.a].

Enforcement. Technical Specification 5.4.1.a requires the implementation of written

procedures described in Regulatory Guide 1.33, Revision 2, Appendix A. Section 9.A of

Regulatory Guide 1.33 requires procedures for performing maintenance that can affect

the performance of safety-related equipment. Procedure STN IC-294A, Calibration of

CCP A Outboard Bearing and Lube Oil Supply Temperature Indicators BGTI0036

- 39 -

Enclosure 2

and BGTI0040, Revision 0, step 8.2.1, requires that the temperature detector be

removed from its thermowell for calibration. Contrary to the above, on November 23,

2009, a worker removed the thermowell and breached the lube oil subsystem. Because

this violation was determined to be of very low safety significance and was placed in the

corrective action program as Condition Report 21993, this violation is being treated as a

noncited violation in accordance with Section VI.A.1 of the Enforcement Policy:

NCV 05000482/2009005-07, Failure to Follow Procedure Results in Draining of

Emergency Core Cooling System Pump Oil.

1R15 Operability Evaluations (71111.15)

a.

Inspection Scope

The inspectors reviewed the following issues:

October 9, 2009, Source range nuclear instrument (NI)-31 response

November 5, 2009, Essential service water pump seismic operability

The inspectors selected these potential operability issues based on the risk-significance

of the associated components and systems. The inspectors evaluated the technical

adequacy of the evaluations to ensure that technical specification operability was

properly justified and the subject component or system remained available such that no

unrecognized increase in risk occurred. The inspectors compared the operability and

design criteria in the appropriate sections of the technical specifications and USAR 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

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

identifying and correcting any deficiencies associated with operability evaluations.

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

These activities constitute completion of three operability evaluations inspection samples

as defined in Inspection Procedure IP 71111.15-05

b.

Findings

.1

Introduction. On November 5, 2009, the inspectors identified a Green noncited violation

of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,

for failure to perform an adequate operability evaluation as required by procedure.

Description. On November 1, 2009, Wolf Creek was defueled for Refueling Outage 17,

and essential service water pump A was being replaced. On November 1, 2009, Wolf

Creek found that the as-constructed clearances at the essential service water pump A

flange did not meet design requirements. This allowed the pump column to flex up to

0.125 inches until it would engage the seismic supports. The pumps were designed to

be rigidly restrained. This resulted in Condition Reports 21400 and 21572. Wolf Creek

- 40 -

Enclosure 2

completed Operability Evaluation EF-09-010 that provided the basis for the past

operability of essential service water Pump A and future operability of essential service

water pump B on November 1, 2009, and initiated Condition Report 22400 to correct the

clearances.

On November 5, 2009, the inspectors reviewed Operability Evaluation EF-09-010. The

evaluation concluded that the increased movement of the pump would increase stresses

to 10 ksi, which was below the specified allowable ASME Code Section III limit of

17.5 ksi. The evaluation identified requirements that the pumps shall operate during and

after a safe shutdown earthquake as one of the design basis functions as required per

10 CFR Part 50, Appendix A, General Design Criterion 2. These seismic design

requirements are contained in Sections 3.9(B) and 9.2.1 of the USAR. The inspectors

found that the operability evaluations technical basis was inadequate due to the

following: (1) the evaluation did not contain a formal calculation that demonstrated that

stresses were below limits, (2) the evaluation only considered operating basis

earthquake accelerations and not the larger safe shutdown earthquake accelerations,

(3) the evaluation did not contain a calculation to demonstrate that the pump impeller

clearances were allowable if an earthquake occurred while the pump was running, and

(4) the method of analysis for the stresses was not described as an appropriate

alternative method to the original stress calculation done with the SAP V computer

program. The inspectors could not verify that the simplified method was appropriate.

The inspectors reviewed Procedure AP 26C-004, Technical Specification Operability,

Revision 20 and Procedure AP 28-001, Operability Evaluations, Revision 17.

Procedure AP 26C-004, step 6.2.6, states that documentation for prompt operability

evaluations shall include information needed to support operability. Step 4.5 states that

safety functions specified in the current licensing basis shall be met.

Procedure AP 28-001, Operability Evaluations, step 4.9, also describes that the

specified safety functions in the current licensing basis shall be met. Step 6.1.7 states

that design basis events and safety evaluations should be considered. There is no

description of the use of alternative analysis methods in AP 28-001 or AP 26C-004 that

is consistent with Regulatory Information Summary 2005-20, Section C.4.

On November 7, 2009, Wolf Creek initiated Condition Report 21572 to resolve the items

identified above. Wolf Creek completed Operability Evaluation EF-09-010, Revision 1,

on December 14, 2009. The inspectors reviewed Revision 1 and determined the above

identified deficiencies still existed. Wolf Creek performed a third revision to Operability

Evaluation EF-09-010 and initiated Condition Report 22798. The four items were

resolved with Operability Evaluation EF-09-010, Revision 2 which contained drawings

and calculations to demonstrate that the pumps were seismically qualified and that the

simplified calculations were appropriate. In Revision 2, the calculated stresses

increased to 16.4 ksi but were still below the limit of 17.5 ksi.

Analysis. The failure to perform an adequate operability evaluation per

Procedures AP 28-001 and AP 26C-004, was a performance deficiency. Traditional

enforcement does not apply since there were no actual safety consequences or potential

for impacting the NRC's regulatory function, and the finding was not the result of any

willful violation of NRC requirements or Wolf Creek procedures. The inspectors

- 41 -

Enclosure 2

determined that this finding was more than minor because it is associated with the

equipment performance attribute for the Mitigating Systems Cornerstone, and it affected

the cornerstone objective to ensure the availability, reliability, and capability of systems

that respond to initiating events to prevent undesirable consequences (i.e., core

damage). Specifically, this issue relates to the availability and reliability examples of the

equipment performance attribute because a latent common mode failure mechanism

was not correctly evaluated. The inspectors evaluated the significance of this finding

using Phase 1 of Inspection Manual Chapter 0609, Appendix A, "Significance

Determination of Reactor Inspection Findings for At Power Situations," and determined

that the finding was of very low safety significance (Green) because the issue was not a

design or qualification deficiency confirmed to result in loss of operability or functionality,

did not represent a loss of system safety function, an actual loss of safety function of a

single train for greater than its technical specification allowed outage time, an actual loss

of safety function of a nontechnical specification risk-significant equipment train, and did

not screen as potentially risk significant due to a seismic, flooding, or severe weather

initiating event. The cause of the finding has a problem identification and resolution

crosscutting aspect in the area associated with the corrective action program because

Wolf Creek failed to thoroughly evaluate the failure mechanism such that the resolutions

address the causes and extent of conditions, as necessary P.1.c].

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 or procedures of a type appropriate to the circumstances,

accomplished in accordance with those instructions or procedures, and contain

acceptance criteria to demonstrate that the activity was successfully accomplished.

Procedure AP 26C-004, Technical Specification Operability, Revision 20, implements

this requirement and states, in part, that continued operability decisions shall be made in

accordance with Procedure AP 28-001, Operability Evaluations, Revision 17.

Procedure AP 28-001 requires, in part, that operability evaluations shall demonstrate

that equipment meets its design functions. Per Sections 3.9(B) and 9.2.1 of the USAR,

the essential service water pumps are designed to withstand a safe shutdown

earthquake. Contrary to the above, from November 1, 2009, to January 13, 2010,

Operability Evaluation EF-09-010, Revisions 0 and 1, did not demonstrate that the

essential service water pumps could withstand a safe shutdown earthquake.

Specifically, no calculations existed to demonstrate allowable stresses and pump

impeller clearances. Because the finding is of very low safety significance and has been

entered into the corrective action program as Condition Reports 22798 and 21572, this

violation is being treated as a noncited violation, consistent with Section VI.A of the

NRC Enforcement Policy: NCV 05000482/2009005-08, Inadequate Operability

Evaluation of Essential Service Water Pumps.

.2

Introduction. The inspectors identified a Green, noncited violation of Technical

Specification 3.3.1, Condition I, for making positive reactivity addition prohibited by

technical specifications in Mode 2 because one source range nuclear instrument

channel was inoperable.

Description. On August 19, 2009, at 3:47 p.m., a loss of offsite power and reactor trip

occurred. As a result, cavity cooling fans were lost causing an increase in air

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Enclosure 2

temperature in the reactor cavity. Shortly thereafter, the indicated count rate on source

range nuclear instrument NI-31 began increasing from the expected value of about 250

counts per minute (cpm) to 15,000 cpm and then to a maximum of 27,000 cpm over an

8-hour period. Control room operators declared the source range channel NI-31

inoperable as a result of this abnormal behavior. Power to the cavity fans was restored

around 1 a.m. on August 20, 2009, and the source range nuclear instrument NI-31 count

rate returned to its expected value below 250 cpm, based on its anticipated reading

relative to source range NI-32 which did not experience any increase in count rate with a

loss of cavity cooling.

Wolf Creek concluded, based on feedback from the vendor, the most likely cause of the

abnormal readings was moisture intrusion at the cable to detector connection at the

base of the detector inside the reactor cavity. As long as cavity cooling remained

available, the moisture intrusion would not be an issue. Based on this information, Wolf

Creek declared the source range NI-31 operable restarted from the forced outage on

August 23, 2009. Wolf Creeks operability evaluation failed to identify that safety-related

equipment was now reliant on nonsafety cavity cooling fans and nonsafety electrical

power to those fans. The source range instruments NI-31 and -32 are required to be

operable in Mode 2 below the P-6 interlock to monitor the approach to criticality.

During this time, the resident inspectors questioned the operability of source range

instrument NI-31. When entering Refueling Outage 17, a power supply failure in the

control cabinet caused source range NI-31 to fail upon demand during shutdown. On

October 7, 2009, Wolf Creek performed another operability evaluation that stated that

the source range was operable because it had passed its surveillance tests during the

last refueling outage that ended in May 2008. The inspectors noted that this evaluation

did not address the observed problem and therefore did not provide a reasonable basis

for operability. On October 28, 2009, during interviews with Wolf Creek engineering

personnel, the inspectors learned that the original operability determination used to

restart from the forced outage was inaccurate because the equipment configuration in

the field was different than described in the operability determination. The detectors are

in fact hard wired and there are no cabling connections until the containment bio-shield

wall, therefore, no connectors would be affected by the reactor cavity temperature

increase following the loss of cavity cooling fans. Consequently, there was no valid

explanation for the increase in count rate observed on August 19, 2009. Shortly

thereafter, Wolf Creek replaced the source range NI-31 detector before restart from

Refueling Outage 17 to definitively restore operability to the channel.

On November 13, 2009, the resident inspectors observed the removal of source range

Detector SE-0031 from the reactor cavity. There was some minor damage to the outer

layer of cable wrap, however, nothing was observed that could conclusively explain the

detectors malfunction on August 19, 2009, or ensure its future operability. Wolf Creek

USAR, Chapter 15, credits low power reactor trips as being terminated by the power

range instruments. The power range instruments are not required to be operable in

Mode 3. USAR, Chapter 15, credits the source range and intermediate range reactor

trips to stop reactivity excursions at a much lower power. This allows technical

specifications to credit these trips in Mode 3. During the shutdown in August 2009, rod

drive motor-generator set testing was performed which cycled the reactor trip breakers

- 43 -

Enclosure 2

and made the control rods capable of withdrawal. The inspectors also reviewed the

technical specification bases for the source range which stated that they are required to

perform a monitoring function of neutron levels and provide indication of reactivity

changes that may occur.

Analysis. Reactivity addition with source range channel nuclear instrument-31

inoperable is a performance deficiency. The finding was more than minor because it

was associated with the configuration control (reactivity control) attribute of the Barrier

Integrity Cornerstone, and it affected the cornerstone objective to provide reasonable

assurance that physical design barriers (fuel cladding, reactor coolant system, and

containment) protect the public from radionuclide releases caused by accidents or

events. The inspectors evaluated the significance of this finding using Phase 1 of

Inspection Manual Chapter 0609.04, and determined that the finding screened to Green

because the finding only affected the fuel barrier. Additionally, the cause of the finding

has a human performance crosscutting aspect in the area associated with the decision

making. Specifically, Wolf Creek did not use conservative assumptions in decision

making and adopt requirements to demonstrate that the proposed action is safe in order

to proceed rather than a requirement to demonstrate that it is unsafe in order to

disapprove the action, when performing an operability evaluation for the source range

Nuclear Instrument 31 detector prior to restarting from a forced outage H.1(b).

Enforcement. Wolf Creek Technical Specification LCO 3.3.1 Reactor Trip System

Instrumentation, Condition I, requires immediate suspension of all operations activities

involving positive reactivity additions when one source range channel is inoperable while

in Mode 2. Contrary to the above on August 22, 2009, at 11:10 a.m., Wolf Creek

entered Mode 2 with one source range channel inoperable and continued withdrawing

control rods until the reactor was critical at 11:54 a.m. At that time, Wolf Creek went

above the P-6 interlock and source range monitoring was no longer required by technical

specifications. Because the finding is of very low safety significance and has been

entered into the corrective action program as Condition Report 20208, this violation is

being treated as a noncited violation, consistent with Section VI.A of the NRC

Enforcement Policy: NCV 05000482/2009005-09, Positive Reactivity Addition

Prohibited by technical specifications while in Mode 2.

1R18 Plant Modifications (71111.18)

Permanent Modifications

The inspectors reviewed key affected parameters associated with energy needs,

materials, replacement components, timing, heat removal, control signals, equipment

protection from hazards, operations, flow paths, pressure boundary, ventilation

boundary, structural, process medium properties, licensing basis, and failure modes for

the permanent modifications listed below.

December 16, 2009, Instrument setpoints for reactor coolant pump thermal

barrier isolation and Valve EGHV62

- 44 -

Enclosure 2

The inspectors reviewed key parameters associated with energy needs, materials,

replacement components, timing, heat removal, control signals, equipment protection

from hazards, operations, flow paths, pressure boundary, ventilation boundary,

structural, process medium properties, licensing basis, and failure modes for the

permanent modification identified as configuration Change Package 013096.

The inspectors verified that modification preparation, staging, and implementation did not

impair emergency/abnormal operating procedure actions, key safety functions, or

operator response to loss of key safety functions; postmodification testing will maintain

the plant in a safe configuration during testing by verifying that unintended system

interactions will not occur; systems, structures and components, performance

characteristics still meet the design basis; the modification design assumptions were

appropriate; the modification test acceptance criteria will be met; and licensee personnel

identified and implemented appropriate corrective actions associated with permanent

plant modifications. Specific documents reviewed during this inspection are listed in the

attachment.

These activities constitute completion of one sample for permanent plant modifications

as defined in Inspection Procedure IP 71111.18-05.

b.

Findings

Introduction. On December 16, 2009, inspectors identified a Green noncited violation of

10 CFR Part 50, Appendix B, Criterion III, Design Control, involving failure to obtain

vendor design data for a modification.

Description. On December 16, 2009, the inspectors reviewed configuration change

Package 013096 from August 2009 which modified the upper flow limit through the

reactor coolant pump thermal barrier heat exchangers from 60 to 68 gpm. The change

package cited an internal memo from 1992 as the justification for the increased flow.

The inspectors reviewed the internal memo and noted that it described the thermal

barrier outlet valves going closed on high flow. It also indirectly described a telephone

conversation with a Westinghouse representative who stated that the thermal barriers

were capable of up to 90 gpm sustained flow. The inspectors found no accompanying

data from Westinghouse to justify this claim. Procedure AP 05-005, Design Control,

required that vendor data be obtained in accordance with Procedure AP 05-013, Review

of Vendor Technical Documents, Revision 7A. The inspectors reviewed

Procedure AP 05-013 and noted that it stated that documentation would be obtained

from the vendor consistent with procurement standards for acceptance.

Procedure AP 05-013, step 6.5, specified evaluation of vendor technical documentation,

but it did not specify how to disposition informal information. This step required a review

of vendor documentation by engineering to ensure design requirements are met.

Procedure AP 05-013, step 6.6, specified incorporating changes to vendor documents

that originate with Wolf Creek, but it did not specify that the vendor must be contacted for

changes that Wolf Creek has not evaluated.

Procedure AP 05-002, Dispositions and Change Packages, Revision 8, specified how

Wolf Creek prepares, documents, and implements modifications to plant equipment and

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Enclosure 2

design documents. Procedure AP 05-002, step 6.4.5, required that the data be obtained

from the vendor and placed in the modification package supporting the plant change.

Procedure AP 05-002, step 6.4.6.6, did not allow informal communications to form the

basis for a modification. Telephone calls are defined as informal communication per

Procedure AP 05-005. The inspectors found no documentation to show validation of the

verbal data provided by the vendor. This modification was a corrective action to

VIO 05000482/2009002-07 (EA-09-110). This notice of violation will remain open until

full compliance has been restored. Wolf Creek subsequently consulted with

Westinghouse to confirm the acceptability of the increased flow rate, and requested a

formal calculation. This issue is captured in Condition Report 22824.

Analysis. The inspectors found that the failure to follow procedure for the modification

was a performance deficiency. Traditional enforcement does not apply since there were

no actual safety consequences or potential for impacting the NRC's regulatory function,

and the finding was not the result of any willful violation of NRC requirements or Wolf

Creek procedures. The inspectors determined that this finding was more than minor

because this issue aligned with Inspection Manual Chapter 0612, Appendix E,

example 2.f, in that the modification relied on verbal statements to raise the allowable

flow through the heat exchanger. This is a significant deficiency in the modification

package. The inspectors determined this finding was associated with the design control

attribute of the Initiating Events Cornerstone and affected the cornerstone objective to

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

functions. The inspectors evaluated the significance of this finding using Phase 1 of

Inspection Manual Chapter 0609.04 and determined that the finding was of very low

safety significance because assuming worst case degradation, the finding would not

result in exceeding the technical specification limit for identified reactor coolant system

leakage and would not have likely affected other mitigation systems resulting in a total

loss of their safety function because seal injection was available. This finding has a

crosscutting aspect in the area of human performance associated with work practices in

that management was unsuccessful in communicating expectations on procedure use

and adherence in engineering H.4.b].

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control," requires,

in part, that the licensee establish measures for the identification and control of design

interfaces and for coordination among participating design organizations. These

measures shall include the establishment of procedures among participating design

organizations for the review, approval, release, distribution, and revision of documents

involving design interfaces. It also requires, in part, that design changes shall be subject

to design control measures commensurate with those applied to the original design.

Procedures AP 05-005 and AP 05-002 implement this requirement by requiring formal

vendor data required for modifications to be incorporated into modifications. Contrary to

the above, from August 13, 2009, to December 31, 2009, Wolf Creek failed to obtain

vendor design data for configuration change Package 013096 in accordance with

Procedures AP 05-005 and AP 05-002. Because the finding is of very low safety

significance and has been entered into the corrective action program as Condition

Report 22824, this violation is being treated as a noncited violation, consistent with

Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-10, Failure to

Obtain Vendor Data Necessary for Plant Modification.

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Enclosure 2

1R19 Postmaintenance Testing (71111.19)

a.

Inspection Scope

The inspectors reviewed the following postmaintenance activities to verify that

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

capability:

October 23, 2009, Emergency diesel generator A run after replacement of speed

switch

October 23, 2009, Instrumentation and control testing of emergency diesel

generator A instrument power supply

November 6, 2009, Essential service water train B pump and motor replacement

November 2, 2009, Motor-operated valve MOV 8811A after actuator and internals

replacement

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

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

following (as applicable):

The effect of testing on the plant had been adequately addressed; testing was

adequate for the maintenance performed

Acceptance criteria were clear and demonstrated operational readiness; test

instrumentation was appropriate

The inspectors evaluated the activities against the technical specifications, the USAR,

10 CFR Part 50 requirements, licensee procedures, and various NRC generic

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

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

corrective action documents associated with postmaintenance tests to determine

whether the licensee was identifying problems and entering them in the corrective action

program and that the problems were being corrected commensurate with their

importance to safety. Specific documents reviewed during this inspection are listed in

the attachment.

These activities constitute completion of four postmaintenance testing inspection

samples as defined in Inspection Procedure IP 71111.19-05.

b.

Findings

No findings of significance were identified.

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Enclosure 2

1R20 Refueling and Other Outage Activities (71111.20)

a.

Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Wolf

Creek refueling outage, conducted from October 10 to November 17 2009, to confirm

that licensee personnel had appropriately considered risk, industry experience, and

previous site-specific problems in developing and implementing a plan that assured

maintenance of defense in depth. During the refueling outage, the inspectors observed

portions of the shutdown and cooldown processes and monitored licensee controls over

the outage activities listed below.

Configuration management, including maintenance of defense in depth, is

commensurate with the outage safety plan for key safety functions and

compliance with the applicable technical specifications when taking equipment

out of service.

Clearance activities, including confirmation that tags were properly hung and

equipment appropriately configured to safely support the work or testing.

Installation and configuration of reactor coolant pressure, level, and temperature

instruments to provide accurate indication, accounting for instrument error.

Status and configuration of electrical systems to ensure that technical

specifications and outage safety-plan requirements were met, and controls over

switchyard activities.

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

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

operate the spent fuel pool cooling system.

Reactor water inventory controls, including flow paths, configurations, and

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

Controls over activities that could affect reactivity.

Maintenance of secondary containment as required by the technical

specifications.

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

leakage.

Startup and ascension to full power operation, tracking of startup prerequisites,

walkdown of the drywell (primary containment) to verify that debris had not been

left which could block emergency core cooling system suction strainers, and

reactor physics testing.

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Enclosure 2

Licensee identification and resolution of problems related to refueling outage

activities.

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

These activities constitute completion of one refueling outage and other outage

inspection sample as defined in Inspection Procedure IP 71111.20-05.

b.

Findings

.1

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

Appendix B, Criterion III, Design Control, for failure to correct a previous violation for an

inadequate vent path for the reactor vessel head.

Description. NRC Inspection Report 05000482/2008004 documented a Green noncited

violation of 10 CFR Part 50, Criterion III, Design Control, associated with the formation

of voids in the reactor vessel head during refueling outages.

During Refueling Outage 17 on October 13, 2009, Wolf Creek depressurized the reactor

and drained the reactor coolant system via the pressurizer to a level 374 inches above

the bottom of the hot leg. Reactor coolant system pressure was established at

atmospheric pressure, approximately 6-10 psig below the volume control tank pressure.

These actions were performed in accordance with plant operating

Procedure SYS BB-215, RCS Drain Down with Fuel in Reactor. The operators

completed Sections 6.1 and 6.2 of the procedure to vent the reactor vessel head to the

pressurizer and purge the pressurizer with nitrogen.

Control room operators subsequently initiated Condition Reports 20648 and 20633 to

identify anomalous readings in pressurizer and reactor vessel level. The inspectors

reviewed plant computer data from October 11 to 14, 2009, and confirmed that a void

had formed in the reactor vessel head region following reactor coolant system

depressurization. As the gas built up, it forced primary coolant out of the reactor vessel

and into the pressurizer over many hours, causing the observed level changes.

Following the previous refueling outage, Wolf Creek Mode 5 Procedure GEN 00-009 had

been changed to require reactor vessel level instrumentation system to be in service so

that control room operators could observe any decrease in reactor vessel level. Based

on plant computer data, the observed change of approximately 41 inches in pressurizer

level equated to a maximum void size of 1100 gallons of primary coolant in the reactor

vessel. Excluding the void, time to boil in the reactor coolant system was calculated to

be 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> during outage planning.

Following the formation of a similar void in Refueling Outage 16, Wolf Creek initiated a

root cause evaluation during under Condition Report 2008-001032. The void size during

Refueling Outage 16 was 2600 gallons. Wolf Creek determined that the root cause was

a loop seal or blockage in the piping. The root cause described boron precipitation as a

possible source of the blockage. Corrective actions were subsequently planned for

Refueling Outage 17. The slope of the vessel head piping was verified to be correct to

ensure no loop seals was performed as a corrective action to prevent recurrence.

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Enclosure 2

However, after the piping slope was verified and loop seals ruled out as a possible

cause, no additional actions were taken to identify the cause of the inadequate vent. A

corrective action to perform an internal inspection of the vessel head was not performed

because Wolf Creek did not have tools to inspect around 90 bends in the piping. The

inspectors determined that Wolf Creek failed to identify the cause of the inadequate vent

path to relieve gases to the pressurizer, with the result that voiding would continue to be

a concern in the next refueling outage.

When the NRC issued NCV 05000482/2008004-07 on November 7, 2008, for the

reactor vessel head voiding during outages, corrective actions were tracked under

Condition Report 2008-001032. The inspectors concluded that Wolf Creek has yet to

correct the inadequate vent path, allowing void formation to continue to occur in the

reactor vessel head. Without an adequate vent from the top of the reactor vessel head

to the pressurizer, noncondensable gas voids will form, decreasing reactor coolant

inventory and reducing the time to core boiling following a loss of shutdown cooling. The

gas voids could grow to the top of the hot legs or until the driving head forces the void

past the blockage and into the gas space of the pressurizer, causing the plant to

inadvertently enter mid-loop operations. An adequate vent path is necessary to control

reactor coolant level. Wolf Creek has initiated a second root cause under Condition

Report 22501.

Analysis. The inspectors determined that failure to provide an adequate vessel head

vent path to prevent gas accumulation in the reactor vessel during depressurized plant

operations was a performance deficiency. The inspectors determined that this finding

was associated with the design control attribute of the Initiating Events Cornerstone.

Specifically, the voiding reduces time to boil and impacted 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. The inspectors evaluated the

significance of this finding using Inspection Manual Chapter 0609, Appendix G,

Attachment 1, Shutdown Operations Significance Determination Process Phase 1

Operational Checklists for Both PWRs and BWRs. The inspectors determined that

Checklist 3 was applicable because the unit was in cold shutdown with the refueling

cavity level less than 23 feet. Based upon Appendix G, Attachment 1, Checklist 3,

Phase 2, analysis was not needed to characterize the risk significance of this finding

because the level of loss was less than two feet, did not occur during reduced inventory,

and appropriate action was taken regarding the level deviation. The finding was

determined to be of very low safety significance based upon the demonstrated

availability of mitigation systems and the reactor coolant system cavity inventory. The

inspectors determined the cause of the finding had a problem identification and

resolution aspect in the corrective action program. Specifically, Wolf Creeks corrective

actions were not successful to address the vent path blockage in a timely manner

P.1(d).

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires,

in part, that the design basis is correctly translated into specifications, drawings, and

procedures. The design basis of the reactor vessel head vent is to allow

noncondensable gases to escape to the pressurizer during shutdown conditions.

Contrary to the above, from December 2, 2003, to December 31, 2009, Wolf Creek

- 50 -

Enclosure 2

failed to ensure the design basis of the reactor vessel head vent was correctly translated

into specifications, drawings, and procedures. Specifically, Wolf Creek designed and

installed a reactor vessel head permanent vent piping modification which failed to vent

noncondensable gases to the pressurizer during shutdown operations. This resulted in

the formation of voids in the reactor vessel head while the plant was shutdown and

depressurized in successive refueling outages. This issue and the corrective actions are

being tracked by the licensee in Condition Reports 22501, 20648, 20568, and 20633.

Due to the licensees failure to restore compliance from previous

NCV 05000482/2008004-07 within a reasonable time after the violation was identified,

this violation is being cited as a Notice of Violation consistent with Section VI.A of the

Enforcement Policy: VIO 05000482/2009005-11, Failure to Correct Vessel Head Vent

Path (EA-10-020).

.2

Introduction. The inspectors identified a Green noncited violation of Technical

Specification 5.4.1.a for failure to properly implement Procedure AP 14A-003, Scaffold

Construction and Use, when scaffolding was erected against operable safety-related

equipment.

Description. On October 15, 2009, the inspectors identified scaffolding in contact with

component cooling water piping inside containment. The piping was the containment

loop which did not have any required cooling loads, but was part of an operating

component cooling water train that was cooling the core. At the time, reactor coolant

system level was below the vessel flange. The tag on the scaffold explicitly stated that it

was not seismically qualified. The inspectors discussed the issue with the shift manager

who immediately had the scaffold moved. Both steam generators were inoperable and

both trains of residual heat removal were required to be operable. The inspectors

reviewed the bases for Technical Specification 3.4.7, RCS Loops - Mode 5, Loops

Filled, which required an operable heat sink path from residual heat removal to

component cooling water to essential service water.

Procedure AP 14A-003, Scaffold Construction and Use, step 6.4.15, required

scaffolding to be two inches away from equipment. Attachment F of this procedure

specifies the requirements for seismically qualified scaffolds. The scaffold form stated

that the scaffolding was required to be removed prior to Mode 4, which was incorrect

because it allowed nonseismically qualified scaffold to be installed in the zone of

influence of operable equipment since seismic qualification is still required for equipment

required to be operable in Modes 5 and 6. This issue was entered into the corrective

action program as Condition Report 22464.

Analysis. The construction of an unqualified scaffold against operable component

cooling water piping was a performance deficiency. Traditional enforcement does not

apply since there were no actual safety consequences or potential for impacting the

NRC's regulatory function, and the finding was not the result of any willful violation of

NRC requirements or Wolf Creek procedures. The inspectors determined that this

finding was more than minor because it is associated with the equipment performance

attribute for the Mitigating Systems Cornerstone, and it affected the cornerstone

objective to ensure the availability, reliability, and capability of systems that respond to

initiating events to prevent undesirable consequences (i.e., core damage). Specifically,

- 51 -

Enclosure 2

this issue relates to the availability and reliability examples of the equipment

performance attribute because a latent failure mechanism was not evaluated. The

inspectors evaluated the significance of this finding using Inspection Manual

Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance

Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs. The

inspectors determined that Checklist 3 was applicable because the unit was in cold

shutdown with the refueling cavity level less than 23 feet. Using Appendix G,

Attachment 1, Checklist 3, Phase 2 analysis was not needed and the finding was of very

low safety significance (Green) because the licensee was able to demonstrate that the

seismically unqualified scaffolding would not have resulted in a loss of safety function.

The inspectors determined the cause of the finding had a human performance aspect in

the area of resources. Specifically, Procedure AP 14A-003 was inadequate because it

had conflicting guidance that allowed seismically unqualified scaffolds in Modes 5 and 6

H.2.c].

Enforcement. Technical Specification 5.4.1.a requires that procedures be established,

implemented and maintained as recommended in Regulatory Guide 1.33, Appendix A.

Section 9.a of Appendix A, requires, in part, that maintenance affecting safety-related

equipment be accomplished in accordance with procedures. Procedure AP 14A-003

Scaffold Construction and Use, Revision 16, step 6.4.15 required two inches of

clearance from safety-related structures. Contrary to the above, from October 14 to 15,

2009, the licensee did not provide two inches of clearance between scaffolding and

safety-related structures. Specifically, component cooling water Train B was in contact

with a seismically unqualified scaffold while component cooling water was required to be

operable. Because the finding is of very low safety significance and has been entered

into the corrective action program as Condition Report 22464, this violation is being

treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement

Policy: NCV 05000482/2009005-12, Unevaluated Scaffold Against Component Cooling

Water Piping.

1R22 Surveillance Testing (71111.22)

a.

Inspection Scope

The inspectors reviewed the USAR, procedure requirements, and technical

specifications to ensure that the seven surveillance activities listed below demonstrated

that the systems, structures, and/or components tested were capable of performing their

intended safety functions. The inspectors either witnessed or reviewed test data to verify

that the significant surveillance test attributes were adequate to address the following:

Preconditioning

Evaluation of testing impact on the plant

Acceptance criteria

Test equipment

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Enclosure 2

Procedures

Jumper/lifted lead controls

Test data

Testing frequency and method demonstrated technical specification operability

Test equipment removal

Restoration of plant systems

Fulfillment of ASME Code requirements

Updating of performance indicator data

Engineering evaluations, root causes, and bases for returning tested systems,

structures, and components not meeting the test acceptance criteria were correct

Reference setting data

Annunciators and alarms setpoints

The inspectors also verified that licensee personnel identified and implemented any

needed corrective actions associated with the surveillance testing.

October 28, 2009, MOV 8811A as-found inservice surveillance test

August 10, 2009, STS IC-250B, Channel operational test containment

atmosphere and reactor coolant system leak rate radiation Monitor GT RE-0031

November 5, 2009, STS PE-139, Local leak rate test of Penetration 39,

BB HV-351C

September 17, 2009, Train A auxiliary feedwater inservice testing of

Valves ALV0002 and ALV0009

November 3, 2009, Essential service water Train B leak test of underground pipe

September 28, 2009, Emergency Diesel Generator A, 24-hour endurance run

October 15, 2009, Emergency Diesel Panel KJ-122/123 safety to nonsafety fuse

inspections

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

These activities constitute completion of seven surveillance testing inspection samples

as defined in Inspection Procedure IP 71111.22-05.

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Enclosure 2

b.

Findings

No findings of significance were identified.

2.

RADIATION SAFETY

Cornerstone: Occupational and Public Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a.

Inspection Scope

This area was inspected to assess licensee personnels performance in implementing

physical and administrative controls for airborne radioactivity areas, radiation areas, high

radiation areas, and worker adherence to these controls. The inspectors used the

requirements in 10 CFR Part 20, the technical specifications, and the licensees

procedures required by technical specifications as criteria for determining compliance.

During the inspection, the inspectors interviewed the radiation protection manager,

radiation protection supervisors, and radiation workers. The inspectors performed

independent radiation dose rate measurements and reviewed the following items:

Performance indicator events and associated documentation packages reported

by the licensee in the Occupational Radiation Safety Cornerstone

Controls (surveys, posting, and barricades) of radiation, high radiation, or

airborne radioactivity areas

Radiation work permits, procedures, engineering controls, and air sampler

locations

Conformity of electronic personal dosimeter alarm set points with survey

indications and plant policy; workers knowledge of required actions when their

electronic personnel dosimeter noticeably malfunctions or alarms

Barrier integrity and performance of engineering controls in airborne radioactivity

areas

Physical and programmatic controls for highly activated or contaminated

materials (nonfuel) stored within spent fuel and other storage pools

Self-assessments, audits, licensee event reports, and special reports related to

the access control program since the last inspection

Corrective action documents related to access controls

Licensee actions in cases of repetitive deficiencies or significant individual

deficiencies

- 54 -

Enclosure 2

Radiation work permit briefings and worker instructions

Adequacy of radiological controls, such as required surveys, radiation protection

job coverage, and contamination control during job performance

Dosimetry placement in high radiation work areas with significant dose rate

gradients

Changes in licensee procedural controls of high dose rate - high radiation areas

and very high radiation areas

Controls for special areas that have the potential to become very high radiation

areas during certain plant operations

Posting and locking of entrances to all accessible high dose rate - high radiation

areas and very high radiation areas

Radiation worker and radiation protection technician performance with respect to

radiation protection work requirements

Either because the conditions did not exist or an event had not occurred, no

opportunities were available to review the following items:

Adequacy of the licensees internal dose assessment for any actual internal

exposure greater than 50 millirem committed effective dose equivalent

These activities constitute completion of 21 of the required 21 samples as defined in

Inspection Procedure IP 71121.01-05.

b.

Findings

.1

Introduction. The inspector identified a Green noncited violation of

Technical Specification 5.7.2.a.1 for failure to maintain administrative control of door

and gate keys to high radiation areas with dose rates greater than 1 rem per hour but

less than 500 rads per hour (referred to as locked high radiation areas).

Description. During a review of the licensees program for administrative control of

keys to doors and gates to locked high radiation areas and very high radiation areas, the

inspector found that the health physics department had a master key to locked high

radiation areas. This key was not controlled in accordance with licensee

Procedure AP 25A-200, Access to Locked High or Very High Radiation Areas,

Revision 20, which stated that site security was responsible for issuing locked high

radiation area and very high radiation area keys. In accordance with technical

specifications, health physics management designated the site security department to

administratively (and procedurally) control the keys. Although site security was

effectively meeting the procedure requirement for issuing all other locked and very high

- 55 -

Enclosure 2

radiation area keys, site security was unaware that the health physics department had

the only master key to locked high radiation areas at the site. By procedure, site security

administratively controlled the other keys (to locked and very high radiation areas) by

maintaining an inventory of them, performing physical inventories of the keys each shift,

and labeling the keys. None of these administrative controls were implemented for the

master key in the health physics department. The licensee immediately documented the

deficiency in a condition report and implemented temporary administrative controls until

a permanent disposition for the master key had been identified.

Analysis. Failure to maintain administrative control of the master key to locked high

radiation areas was a performance deficiency. This finding is greater than minor because if

left uncorrected the finding has the potential to lead to a more significant safety concern in

that an individual could receive unanticipated radiation dose by gaining access a locked high

radiation area without the proper controls and briefing. This finding was evaluated using

Inspection Manual Chapter 0609, Significance Determination Process, Appendix C,

Occupational Radiation Safety Significance Determination Process, and was determined to

be of very low safety significance because it did not involve: (1) an as low as is reasonably

achievable (ALARA) planning or work control issue, (2) an overexposure, (3) a substantial

potential for overexposure, or (4) an impaired ability to assess dose. Additionally, the

violation has a crosscutting aspect in the area of human performance associated with the

work practices component because the lack of peer and self-checking resulted in

inadequate control of keys to locked high radiation areas H.4(a).

Enforcement. Technical Specification 5.7.2.a.1 requires, in part, that each entryway to a

high radiation area with dose rates greater than 1.0 rem per hour but less than 500 rads

per hour shall be provided with a locked or continuously guarded door or gate that

prevents unauthorized entry and all keys shall be maintained under the administrative

control of the shift manager/control room supervisor, health physics supervision, or

his/her designee. Contrary to the above, as of October 21, 2009, the licensee failed to

maintain administrative control of a master key to high radiation areas with dose rates in

excess of 1.0 rem per hour but less than 500 rads per hour. Because this violation was

of very low safety significance and has been entered into the licensee's corrective action

program as Condition Report 20973, it is being treated as a noncited violation consistent

with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-13, Failure

to Maintain Administrative Control of Keys to Locked High Radiation Areas.

2OS2 ALARA Planning and Controls (71121.02)

a.

Inspection Scope

The inspectors assessed licensee personnels performance with respect to maintaining

individual and collective radiation exposures as low as is reasonably achievable. The

inspectors used the requirements in 10 CFR Part 20 and the licensees procedures

required by technical specifications as criteria for determining compliance. The

inspectors interviewed licensee personnel and reviewed the following:

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Enclosure 2

Five outage or on-line maintenance work activities scheduled during the

inspection period and associated work activity exposure estimates which were

likely to result in the highest personnel collective exposures

Site-specific ALARA procedures

ALARA work activity evaluations, exposure estimates, and exposure mitigation

requirements

Interfaces between operations, radiation protection, maintenance, maintenance

planning, scheduling and engineering groups

Shielding requests and dose/benefit analyses

Dose rate reduction activities in work planning

Use of engineering controls to achieve dose reductions and dose reduction

benefits afforded by shielding

Workers use of the low dose waiting areas

First-line job supervisors contribution to ensuring work activities are conducted in

a dose efficient manner

Radiation worker and radiation protection technician performance during work

activities in radiation areas, airborne radioactivity areas, or high radiation areas

Self-assessments, audits, and special reports related to the ALARA program

since the last inspection

Corrective action documents related to the ALARA program and follow-up

activities, such as initial problem identification, characterization, and tracking

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

These activities constitute completion of 6 of the required 15 samples and 6 of the

optional samples as defined in Inspection Procedure IP 71121.02-05.

b.

Findings

No findings of significance were identified.

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Enclosure 2

4.

OTHER ACTIVITIES

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 3rd

Quarter 2009 performance indicators for any obvious inconsistencies prior to its public

release in accordance with Inspection Manual Chapter 0608, Performance Indicator

Program.

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

as such, did not constitute a separate inspection sample.

b.

Findings

No findings of significance were identified.

.2

Mitigating Systems Performance Index - Emergency ac Power System

a.

Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index - Emergency ac Power System performance indicator data for the period from the

4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

definitions and guidance contained in Revision 6 of the Nuclear Energy Institute (NEI)

Document 99-02, Regulatory Assessment Performance Indicator Guideline, were

used. The inspectors reviewed the licensees operator narrative logs, mitigating systems

performance index derivation reports, issue reports, event reports, and NRC integrated

inspection reports for the period of October 1, 2008, through September 30, 2009, to

validate the accuracy of the submittals. The inspectors reviewed the mitigating systems

performance index component risk coefficient to determine if it had changed by more

than 25 percent in value since the previous inspection, and if so, that the change was in

accordance with applicable NEI guidance. The inspectors also reviewed the licensees

issue report database to determine if any problems had been identified with the

performance indicator data collected or transmitted for this indicator and none were

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

This inspection constitutes one mitigating systems performance index - emergency ac

power system sample as defined by Inspection Procedure IP 71151.

b.

Findings

No findings of significance were identified.

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Enclosure 2

.3

Mitigating Systems Performance Index - High Pressure Injection Systems

a.

Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index - High Pressure Injection Systems performance indicator data for the period from

the 4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

definitions and guidance contained in Revision 6 of the NEI Document 99-02,

Regulatory Assessment Performance Indicator Guideline, were used. The inspectors

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

performance index derivation reports, event reports, and NRC integrated inspection

reports for the period of October 1, 2008, through September 30, 2009, to validate the

accuracy of the submittals. The inspectors reviewed the mitigating systems performance

index component risk coefficient to determine if it had changed by more than 25 percent

in value since the previous inspection, and if so, that the change was in accordance with

applicable NEI guidance. The inspectors also reviewed the licensees issue report

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

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

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

This inspection constitutes one mitigating systems performance index - high pressure

injection system sample as defined by Inspection Procedure IP 71151.

b.

Findings

No findings of significance were identified.

.4

Mitigating Systems Performance Index - Auxiliary Feedwater System

a.

Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index - Auxiliary Feedwater System performance indicator data for the period from the

4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

definitions and guidance contained in Revision 6 of the NEI Document 99-02,

Regulatory Assessment Performance Indicator Guideline, were used. The inspectors

reviewed the licensees operator narrative logs, issue reports, event reports, mitigating

systems performance index derivation reports, and NRC integrated inspection reports

for the period of October 1, 2008, through September 30, 2009, to validate the accuracy

of the submittals. The inspectors reviewed the mitigating systems performance index

component risk coefficient to determine if it had changed by more than 25 percent in

value since the previous inspection, and if so, that the change was in accordance with

applicable NEI guidance. The inspectors also reviewed the licensees issue report

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

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

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

- 59 -

Enclosure 2

This inspection constitutes one mitigating systems performance index - auxiliary

feedwater sample as defined by Inspection Procedure IP 71151.

b.

Findings

No findings of significance were identified.

.5

Mitigating Systems Performance Index - Residual Heat Removal System

a.

Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index - Residual Heat Removal System performance indicator data for the period from

the 4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

definitions and guidance contained in Revision 6 of the NEI Document 99-02,

Regulatory Assessment Performance Indicator Guideline, were used. The inspectors

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

performance index derivation reports, event reports, and NRC integrated inspection

reports for the period of October 1, 2008, through September 30, 2009, to validate the

accuracy of the submittals. The inspectors reviewed the mitigating systems

performance index component risk coefficient to determine if it had changed by more

than 25 percent in value since the previous inspection, and if so, that the change was in

accordance with applicable NEI guidance. The inspectors also reviewed the licensees

issue report database to determine if any problems had been identified with the

performance indicator data collected or transmitted for this indicator and none were

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

This inspection constitutes one Mitigating Systems Performance Index - Residual Heat

Removal System sample as defined by Inspection Procedure IP 71151.

b.

Findings

No findings of significance were identified.

.6

Mitigating Systems Performance Index - Cooling Water Systems

a.

Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index - Cooling Water Systems performance indicator data for the period from the 4th

quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

definitions and guidance contained in Revision 6 of the NEI Document 99-02,

Regulatory Assessment Performance Indicator Guideline, were used. The inspectors

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

performance index derivation reports, event reports, and NRC integrated inspection

reports for the period of October 1, 2008, to September 30, 2009, to validate the

- 60 -

Enclosure 2

accuracy of the submittals. The inspectors reviewed the mitigating systems

performance index component risk coefficient to determine if it had changed by more

than 25 percent in value since the previous inspection, and if so, that the change was in

accordance with applicable NEI guidance. The inspectors also reviewed the licensees

issue report database to determine if any problems had been identified with the

performance indicator data collected or transmitted for this indicator and none were

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

This inspection constitutes one mitigating systems performance index - cooling water

system sample as defined by Inspection Procedure IP 71151.

b.

Findings

No findings of significance were identified.

.7

Occupational Exposure Control Effectiveness (OR01)

a.

Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological

Occurrences performance indicator for the period from the 4th quarter 2008 through 3rd

quarter 2009. To determine the accuracy of the performance indicator data reported

during those periods, performance indicator definitions and guidance contained in NEI

Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6,

was used. The inspectors reviewed the licensees assessment of the performance

indicator for occupational radiation safety to determine if indicator related data was

adequately assessed and reported. To assess the adequacy of the licensees

performance indicator data collection and analyses, the inspectors discussed with

radiation protection staff, the scope and breadth of its data review, and the results of

those reviews. The inspectors independently reviewed electronic dosimetry dose rate

and accumulated dose alarm and dose reports and the dose assignments for any

intakes that occurred during the time period reviewed to determine if there were

potentially unrecognized occurrences. The inspectors also conducted walkdowns of

numerous locked high and very high radiation area entrances to determine the adequacy

of the controls in place for these areas.

These activities constitute completion of the occupational radiological occurrences

sample as defined in Inspection Procedure IP 71151-05.

b.

Findings

No findings of significance were identified.

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Enclosure 2

.8

Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (PR01)

a.

Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent Technical

Specifications/Offsite Dose Calculation Manual Radiological Effluent Occurrences

performance indicator for the period from the 4th quarter 2008 through 3rd quarter 2009.

To determine the accuracy of the performance indicator data reported during those

periods, performance indicator definitions and guidance contained in NEI

Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6,

was used. The inspectors reviewed the licensees issue report database and selected

individual reports generated since this indicator was last reviewed to identify any

potential occurrences such as unmonitored, uncontrolled, or improperly calculated

effluent releases that may have impacted offsite dose.

These activities constitute completion of the radiological effluent technical

specifications/offsite dose calculation manual radiological effluent occurrences sample

as defined in Inspection Procedure IP 71151-05.

b.

Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

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

Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical

Protection

.1

Routine Review of Identification and Resolution of Problems

a.

Inspection Scope

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

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

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

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

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

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

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

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

implications, common causes, contributing factors, root causes, extent of condition

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

and timeliness of corrective actions. Minor issues entered into the licensees corrective

action program because of the inspectors observations are included in the attached list

of documents reviewed.

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Enclosure 2

These routine reviews for the identification and resolution of problems did not constitute

any additional inspection samples. Instead, by inspection procedure, they were

considered an integral part of the inspections performed during the quarter and

documented in Section 1 of this report.

b.

Findings

No findings of significance were identified.

.2

Daily Corrective Action Program Reviews

a.

Inspection Scope

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

human performance issues for followup, the inspectors performed a daily screening of

items entered into the licensees corrective action program. The inspectors

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

The inspectors performed these daily reviews as part of their daily plant status

monitoring activities and, as such, did not constitute any separate inspection samples.

b.

Findings

No findings of significance were identified.

.3

Semi-Annual Trend Review

a.

Inspection Scope

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

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

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

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

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

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

June 30 through December 31, 2009, although some examples expanded beyond those

dates where the scope of the trend warranted.

The inspectors also included issues documented outside the normal corrective action

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

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

audit/surveillance reports, self-assessment reports, and maintenance rule assessments.

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

licensees corrective action program trending reports. Corrective actions associated with

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

adequacy.

These activities constitute completion of one single semi-annual trend inspection sample

as defined in Inspection Procedure IP 71152-05.

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Enclosure 2

b.

Findings

No findings of significance were identified.

.4

Selected Issue Follow-up Inspection

a.

Inspection Scope

The inspectors selected two issues for follow-up inspection per Inspection

Procedure IP 71152. During a review of items entered in the licensees corrective action

program, the inspectors recognized a corrective action item documenting a problem with

extraction steam on June 23, 2009, that caused an increase in reactivity. The inspectors

reviewed corrective actions and new procedure changes for level control of high

pressure feedwater heaters. The inspectors also reviewed several condition reports and

interviewed personnel pertaining to the intermediate range nuclear instrument NI-36.

The deficiencies associated with NI-36 constituted one in-depth review of an operator

work-around.

These activities constitute completion of two in-depth problem identification and

resolution samples as defined in Inspection Procedure IP 71152-05.

b.

Findings

Introduction. On December 30, 2009, the inspectors identified a Green noncited

violation of Technical Specification, Table 3.3.1-1, Function 18.a, when Wolf Creek

restarted from on May 18, 2005.

Description. On April 9, 2005, Wolf Creek shut down for Refueling Outage 14. The

inspectors found no control room log entries stating that source range instrument NI-32

had to be manually energized. The inspectors reviewed a completed copy of

STN IC-236, Revision 4, dated April 9, 2005, which stated that compensation voltage

and current were found within tolerance and were left as-found. At the end of Refueling

Outage 14, in Mode 3, NI-36 indication deviated from indication from intermediate range

detector NI-35. During interviews with licensed operators, when shutdown banks were

withdrawn, NI-36 went above 6 E-11 amps and cleared the P-6 interlock while the

reactor was subcritical. Indication above 6E-11 normally means the reactor is critical.

The source ranges count rates and NI-35 also increased, but did not indicate criticality.

Troubleshooting was performed under Work Order 05-272906-000 was performed on

May 16, 2005. Instrumentation and controls technicians disconnected, cleaned, and

reconnected NI-36 cables. The NI-36 cables were then disconnected and reconnected

two more times. Work Order 05-272906-000 was also used to perform STS IC-436,

Channel Calibration NIS Intermediate Range N-36, Revision 15, test the log current

amplifier and indicator calibrations, Work Order 05-272906-000 was also used to

perform STN IC-236, Intermediate Range N36 Compensation Voltage Adjustment,

Revision 4 to calibrate the compensating voltage power supply and test the loss of

compensating voltage bistable relay driver. On May 17, 2005, during calibration of the

compensating voltage, during step 8.2.4.1, the technicians noted that compensating

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Enclosure 2

voltage was not changing indication permanently, only temporarily. The as-found and

as-left compensating voltage were satisfactory, but the compensating current as-found

and as-left was at 1E-10amps which is one order of magnitude above the 3E-11amps

acceptance criteria. The surveillance was closed stating used only as troubleshooting

tool only. No credit taken. The surveillance test routing sheet noted this as a technical

specification failure. This was then used to generate Work Order 05-272906-000 which

stated that there was a possible problem with the signal cable for NI-32 and the

compensation cable for NI-36 and to rework the cables. The operators had to remove

instrument fuses from the NI-36 instrument rack to cause the interlock to clear after the

efforts below. During control rod pulls during preparations for criticality, the P-6 interlock

came in with the reactor subcritical. Fuses had to later be pulled and re-inserted to clear

the interlock after NI-36 was worked during this series of work orders.

Using Work Order 05-272926-005, the technicians used STS IC-236 to successfully test

the positive and negative 25 Vdc power supplies, the high voltage power supply, the

power above permissive P-6 bistable relay driver, and the reactor trip high level

bistable relay driver. However, other than disconnecting cleaning, and reconnecting the

connectors, no corrective maintenance was performed on cables. The cause of the

failure was documented as suspect loose connection. Wolf Creek concluded that after

the above efforts, that NI-36 indication had been reduced sufficiently to declare it

operable because it channel checked with NI-35 to within one decade. Reactor startup

commenced on May 18, 2005, and concluded Refueling Outage 14.

During a reactor shutdown for Refueling Outage 15 on October 7, 2006, intermediate

range neutron Detector NI-36 did not decrease below 6E -11 amps and energize source

range detector NI-32. Following NI-36s failure to decrease below the P-6 setpoint,

reactor operators correctly transitioned to Procedure OFN SB-008, Instrument

Malfunctions to manually energize source range detector NI-32. On October 7, 2006,

Wolf Creek performed STN IC-236 under Work Order 05-274604-000. Detector NI-36

failed STN IC-236, Intermediate Range N36 Compensation Voltage Adjustment,

Revision 4, because the as-found detector current was outside of the tolerance range at

9E-11 amps (upper limit is 3E-11 amps) and could not be adjusted to within the

tolerance. As-found compensating voltage was within the allowable range.

Wolf Creek then replaced the jacks for the triaxial connector using Work

Order 05-272987-000. Work Order 05-272987-000 stated that the connector was found

failed but did not state what acceptance criteria it did not meet. Work

Order 05-272987-000 stated that the cause of the failure was suspect failed connector.

Also, Work Order 05-272987-000 took measurements of the compensation voltage cable

insulation resistance testing, but stated no acceptance criteria. Work Order 05-272987-

000 the performed surveillance test STS IC-236, Channel Operational Test Nuclear

Instrumentation System Intermediate Range N-36 Protection Set II, Revision 17, which

was followed by Work Order 06-289017-000 to perform STN IC-236. On October 17,

2006, STN IC-236 adjusted the compensating voltage to be more positive. The as-found

adjustment of the detector current was less than 1E-11amps, which was outside the

STN IC-236 acceptance criteria. The inspectors noted that the instrument drawer will

not allow detector current to decrease below 1E-11 amps due to a designed idling

current at 1E-11 amps. As-left current was 1E-11 amps. Later in the outage, control

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Enclosure 2

room operators requested that instrumentation and control workers adjust NI-36

because its output was not tracking with the other intermediate range detector, NI-35.

On November 9, 2006, STN IC-236 was performed again. During this test,

compensation current was unable to be adjusted below 3E-11 amps. The as-found

value was 7E-11 amps and the as-left value was 6E-11 amps. The 6E-11 amp current

was outside the allowable limit, but the surveillance procedure was completed with a

deficiency stating no credit taken. The surveillance cover sheet said that NI-36 was

reading within an order of magnitude of NI-35. The control room logs stated the same.

Work Order 06-290208-000 was generated to replace the detector during the Refueling

Outage 16.

On March 17, 2008, Wolf Creek tripped from 100 percent power and NI-36 automatically

energized source range detector NI-32. The inspectors checked plant computer data

and found that the source range instrument energized at 5E-11 amps which is below the

acceptance criteria of greater than 6 E-11amps (P-6 setpoint). The detector was

subsequently replaced during Refueling Outage 16.

The need to transition to Procedure EMG FR-S2, Response to Loss of Core Shutdown,

was not previously identified in a condition report, operator work around, or operator

burden. The inspectors found no other evaluation of the detectors behavior before Wolf

Creek ascended to Mode 2 in Refueling Outages 14 and 15. The inspectors found that

the connector cleaning in Refueling Outage 14 and the jack replacement in Refueling

Outage 15 were not likely to correct the problem found in STN IC-236. The inspectors

concluded that the STN IC-236 surveillances in Refueling Outage 14 and Refueling

Outage 15 had not met the acceptance criteria and that startup should not have

continued until the nuclear instrument issue was resolved. Wolf Creek did not identify

the issue as a technical specification violation. Although work orders were planned in

Refueling Outage 14 to replace NI-36, all were closed without action. The inspectors

found that NI-36 was conditioned through troubleshooting until it could pass its one

decade channel check. Other testing performed by Wolf Creek only impacted the

instrument drawer in the control room, while the problem was related to the detector

itself. Condition Report 2006-003187 found that the problems with compensating

voltage could not be determined, but concluded that it was not necessary for operability

because the system had no risk significance. The inspectors determined that the

compensation current is critical to the operation of the detectors because the design of

the compensated ion chamber is to allow the instrument drawer to sum currents in

opposing directions to discriminate neutrons from gamma. The condition report also

identified that the P-6 interlock may not work correctly, but no action was taken.

The inspectors reviewed Wolf Creek Technical Specification 3.3.1, Function 18.a,

Intermediate Range Flux, P-6 [interlock], and its bases statement. The bases state

that Function 18.a ensures that, on decreasing power, the P-6 interlock automatically

energizes nuclear instrumentation source range detectors and enables the source range

neutron flux reactor trip. During reactor trip, the function is required as reactor power

decreases to energize the source range detectors and the source range reactor trips.

The inspectors found that Wolf Creeks bases are consistent with the NUREG-1431,

Standard Technical Specifications Westinghouse Plants, Revision 3.0.

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Enclosure 2

Analysis. The inspectors determined that the failure to ensure that the P-6 interlock was

operable per the technical specification as defined in the bases was a performance

deficiency. The finding was more than minor because it was associated with the

configuration control (reactivity control) attribute of the Barrier Integrity Cornerstone, and

it affected the cornerstone objective to provide reasonable assurance that physical

design barriers (fuel cladding, reactor coolant system, and containment) protect the

public from radionuclide releases caused by accidents or events. The inspectors

evaluated the significance of this finding under the Mitigating Systems Cornerstone

using Phase 1 of Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and

Characterization of Findings, and determined that the finding screened to Green

because the P-6 interlock only affected the fuel barrier. This finding was not assigned a

crosscutting aspect because the cause was not representative of current performance.

Enforcement. Wolf Creek Technical Specification, Table 3.3.1-1, Function 18.a,

requires, in part, that when intermediate range instrument measured neutron flux

decreases below the allowable value of greater than or equal to 6 E-11 amps that the

source range instruments be energized and enable the source range reactor trip signal.

Technical Specification, Table 3.3.1-1, Function 4, requires the intermediate range

detectors to be operable at low power in Modes 1 and 2. These functions are required

on reactor trip. Contrary to the above, from May 17, 2005, to March 17, 2008,

intermediate range detector NI-36 was inoperable because its output did not decrease

below the P-6 setpoint when the reactor tripped and failed to energize source range

instrument NI-32 and the source range reactor trip. Because this violation was

determined to be of very low safety significance and was placed in the corrective action

program as Condition Report 00022450, this violation is being treated as a noncited

violation in accordance with Section VI.A.1 of the Enforcement Policy: NCV 05000482/2009005-14, Failure to Identify Inoperable P-6 Interlock and Intermediate

Range Detector.

4OA3 Event Follow-up (71153)

.1

Response to Notice of Unusual Event

On October 22, 2009, Emergency Diesel Generator B was out of service for planned

maintenance. At 12:06 p.m., the Wolf Creek control room received trouble annunciators

for Emergency Diesel Generator A. The speed sensor failed high which would cause

any diesel start to fail. This stopped the jacket water keep warm pump, and prevented

air start system solenoids from starting the engine. Since the engine was in standby, low

lube oil pressure also would have prevented the engine from starting. Wolf Creek

initiated troubleshooting and repair. At 5:39 p.m., Wolf Creek declared an Unusual Event

under Emergency Action Level (EAL) 6/AC5 for loss of both diesels with the reactor

defueled. At 5:45 p.m., Wolf Creek made notification to state and local governments of

the Notice of Unusual Event. At 7:14 p.m., Wolf Creek notified the NRC Operations

Officer that the power supply had excessive voltage ripple which caused the speed

sensors failure. The speed switch and its power supply were replaced. The inspectors

observed control room activities, repair activities, and post-maintenance testing of

repairs. On October 23, 2009, at 7:38 a.m., Emergency Diesel Generator A was

restored to operable status and the unusual event was terminated.

- 67 -

Enclosure 2

b.

Findings

One violation of very low safety significance (Green) is described in Section 4OA7 of this

report.

.2

Licensee Event Report Review

a.

Inspection Scope

The inspectors reviewed potentially reportable events under Inspection

Procedure IP 71153. Inspectors also utilized NUREG 1022, Event Reporting Guidelines

10 CFR 50.72 and 50.73, Revision 2.

b.

Findings

Introduction. The inspectors identified a Severity Level IV noncited violation of

10 CFR 50.73, in which the licensee failed to submit licensee event reports within 60

days following discovery of events or conditions meeting the reportability criteria.

Description. The licensee submitted Licensee Event Report LER 2009-009-00 under

10 CFR 50.73(a)(2)(i)(B) for an operation prohibited by technical specifications. The

inspectors determined this event report was not submitted within the 60 days allowed by

10 CFR 50.73. The inspectors identified that other reporting requirements of 50.73 also

applied but were not included in the licensee event report.

In the event on August 22, 2009, Wolf Creek disabled both trains of the P-4 interlock for

planned maintenance. Specifically, the feedwater isolation signal that is generated by

P-4 (reactor trip coincident with low Tave) was taken out of service for control rod drive

motor-generator set testing. This allowed reactor trip breaker cycling without isolation of

main feedwater. The P-4 interlock was required by Technical Specification 3.3.2 function

8.a. This function is discussed in USAR Section 7.3.8, NSSS Engineered Safety

Feature Actuation System. which describes the function of a main feedwater isolation as

to prevent or mitigate the effect of an excessive cooldown. Wolf Creek technical

specification Bases also state that one or more functions may backup other engineered

safety feature actuation signal functions credited in Chapter 15 of the USAR.

Licensee Event Report 2009-009-00 reported a condition prohibited by technical

specifications under a(2)(i)(B) and correctly described that the P-4 interlock was not

credited in accident analysis. The licensee did not report the event under reporting

criteria 50.73(a)(2)(v). The engineered safety features actuation signal system has other

signals that cause feedwater isolations that are used in Chapter 15 of the USAR.

The inspectors consulted NUREG 1022, Event Reporting Guidelines 10 CFR 50.72

and 50.73, Revision 2. NUREG 1022, Section 3.2.7, reportability under 50.73(a)(2)(v),

specified that inoperable systems required by the technical specifications are to be

reported, even if there are other diverse, operable means of accomplishing the safety

function. The inspectors found that Wolf Creek was not correct in concluding that the

50.73(a)(2)(v)(A) through (D) only applied to the accident analysis contained in

Chapter 15 of the USAR. The inspectors consulted with the NRC Office of Nuclear

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Enclosure 2

Reactor Regulation, who agreed with the inspectors application of the rule and

NUREG 1022. The untimely licensee event report was entered into the corrective action

program as Condition Report 22781.

Analysis. The failure to submit a timely and complete licensee event report was a

performance deficiency. The inspectors reviewed this issue in accordance with

Inspection Manual Chapter 0612 and the NRC Enforcement Manual. Through this

review, the inspectors determined that traditional enforcement was applicable to this

issue because the NRC's regulatory ability was affected. Specifically, the NRC relies on

the licensee to identify and report conditions or events meeting the criteria specified in

regulations in order to perform its regulatory function, and when this is not done, the

regulatory function is impacted. The inspectors determined that this finding was not

suitable for evaluation using the significance determination process, and as such, was

evaluated in accordance with the NRC Enforcement Policy. The finding was reviewed

by NRC management, and because the violation was determined to be of very low

safety significance, was not repetitive or willful, and was entered into the corrective

action program, this violation is being treated as a Severity Level IV noncited violation

consistent with the NRC Enforcement Policy. This finding was determined to have a

crosscutting aspect in the area of problem identification and resolution associated with

the corrective action program in that the licensee failed to appropriately and thoroughly

evaluate for reportability aspects all factors and time frames associated with the

inoperability of the engineered safety features actuation system P.1(c).

Enforcement. Title 10 CFR 50.73(a)(1) requires, in part, that licensees shall submit a

licensee event report for any event of the type described in this paragraph within 60

days after the discovery of the event. Title 10 CFR 50.73(a)(2)(v) requires, in part, that

events or conditions that could have prevented the fulfillment of the safety function of

structures or systems that are needed to shutdown the reactor and maintain it in a safe

shutdown condition, remove residual heat, control the release of radioactive material, or

mitigate the consequences of an accident. Contrary to the above, on October 23, 2009,

Wolf Creek failed to submit a licensee event report within 60 days for removing the P-4

interlock from service, and failed to identify that the condition could have prevented the

fulfillment of the safety function of structures or systems that are needed to mitigate the

consequences of an accident. In accordance with the NRC's Enforcement Policy, the

finding was reviewed by NRC management and because the violation was of very low

safety significance, was not repetitive or willful, and was entered into the corrective

action program, this violation is being treated as a Severity Level IV noncited violation,

consistent with the NRC Enforcement Policy: NCV 05000482/2009005-15, Failure to

Report a Condition that Could Have Prevented Fulfillment of a Safety Function.

4OA5 Other Activities

.1

Quarterly Resident Inspector Observations of Security Personnel and Activities

a.

Inspection Scope

During the inspection period, the inspectors performed observations of security force

personnel and activities to ensure that the activities were consistent with Wolf Creek

- 69 -

Enclosure 2

security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities

did not constitute any additional inspection samples. Rather, they were considered an

integral part of the inspectors normal plant status review and inspection activities.

b.

Findings

No findings of significance were identified.

.2

Temporary Instruction 2515-172, Reactor Coolant System Dissimilar Metal Butt Welds

a.

Inspection Scope:

Portions of Temporary Instruction 2515/172, Reactor Coolant System Dissimilar Metal

Butt Welds, were performed at Wolf Creek during Refueling Outage 17. Specific

documents reviewed during this inspection are listed in the attachment. This unit has

the following dissimilar metal butt welds.

COMPONENT ID

DESCRIPTION

MRP-139

CATEGORY

BASELINE

EXAM

COMMENT

RV-301-121-A

Loop 1 Outlet

Nozzle to Safe-

end weld

D

April 2005

RF14

Next exam:

October 2009

RF17

RV-301-121-B

Loop 2 Outlet

Nozzle to Safe-

end weld

D

April 2005

RF14

Next exam:

October 2009

RF17

RV-301-121-C

Loop 3 Outlet

Nozzle to Safe-

end weld

D

April 2005

RF14

Next exam:

October 2009

RF17

RV-301-121-D

Loop 4 Outlet

Nozzle to Safe-

end weld

D

April 2005

RF14

Next exam:

October 2009

RF17

RV-302-121-A

Loop 1 Inlet

Nozzle to Safe-

end weld

E

April 2005

RF14

Next exam:

April 2011 RF18

RV-302-121-B

Loop 2 Inlet

Nozzle to Safe-

E

April 2005

Next exam:

- 70 -

Enclosure 2

COMPONENT ID

DESCRIPTION

MRP-139

CATEGORY

BASELINE

EXAM

COMMENT

end weld

RF14

April 2011 RF18

RV-302-121-C

Loop 3 Inlet

Nozzle to Safe-

end weld

E

April 2005

RF14

Next exam:

April 2011 RF18

RV-302-121-D

Loop 4 Inlet

Nozzle to Safe-

end weld

E

April 2005

RF14

Next exam:

April 2011 RF18

TBB03-1-W /

MW7090-WOL-DM

Pressurizer surge

nozzle to safe-

end weld

D / F

October 2006

RF15

Note 1

TBB03-2-W /

MW7089-WOL-DM

Pressurizer spray

nozzle to safe-

end weld

D / B

October 2006

RF15

Note 1

TBB03-3-A-W /

MW7086-WOL-DM

Pressurizer

safety nozzle A to

safe-end weld

D / B

October 2006

RF15

Note 1

TBB03-3-B-W /

MW7087-WOL-DM

Pressurizer

safety nozzle B to

Safe-end weld

D / B

October 2006

RF15

Note 1

TBB03-3-C-W /

MW7088-WOL-DM

Pressurizer

safety nozzle C

to safe-end weld

D / F

October 2006

RF15

Note 1

TBB03-4-W /

MW7085-WOL-DM

Pressurizer relief

nozzle to safe-

end weld

D / F

October 2006

RF15

Note 1

Note 1: The pressurizer dissimilar metal butt-welds had full structural weld overlay

applied in Refueling Outage 15. The first Component ID was the designation prior to

overlay, the latter Component ID is the current weld designation (after overlay).

Likewise, the first MRP-139 category was the designation prior to baseline exam and

overlay, and the latter is the current designation (after overlay). Note that these

locations are now examined in accordance with approved alternative of relief

Request I3R-05.

- 71 -

Enclosure 2

03.01 Licensees Implementation of the MRP-139 Baseline Inspections

a.

MRP-139 baseline inspections:

The inspectors reviewed records nondestructive examination activities associated with

the licensees hot leg inspection effort. The baseline inspections of the pressurizer

dissimilar metal butt welds were completed during the spring 2008 Refueling Outage 16.

b.

At the present time, the licensee is not planning to take any deviations from the baseline

inspection requirements of MRP-139, and all other applicable dissimilar metal butt welds

are scheduled in accordance with MRP-139 guidelines.

03.02 Volumetric Examinations

a.

The inspectors reviewed the ultrasonic examination records of the four unmitigated

reactor hot leg nozzles and piping. The inspectors concluded that the ultrasonic

examination for these welds was done in accordance with ASME Code,Section XI,

Supplement VIII, Performance Demonstration Initiative requirements regarding

personnel, procedures, and equipment qualifications. No relevant conditions were

identified during these examinations.

b.

The inspectors reviewed the nondestructive evaluations performed on the four reactor

hot leg nozzles and piping. Inspection coverage met the requirements of MRP-139 and

no relevant conditions were identified.

c.

The certification records of examination personnel were reviewed for those personnel

that performed the examinations of the inspected nozzles. All personnel records

showed that they were qualified under the EPRI Performance Demonstration Initiative.

d.

No deficiencies were identified during the nondestructive evaluations.

03.03 Weld Overlays.

The licensee performed all weld overlays during the previous outage (RF 15).

03.04 Mechanical Stress Improvement

The licensee did not employ a mechanical stress improvement process this outage.

03.05 Inservice inspection program

a.

Inspection Scope:

The licensees MRP-139 program is part of their Alloy 600 program and future

inspections are in accordance with the MRP-139 requirements.

- 72 -

Enclosure 2

b.

Findings

No findings of significance were identified.

.3

(Closed) Unresolved Item 05000482/2008010-04: Operator Actions May Create the

Potential for Secondary Fires

Introduction. The inspectors identified a Green non-cited violation of License

Condition 2.C.(5), Fire Protection, for the failure to implement and maintain the

approved fire protection program. Specifically, the licensee prescribed mitigating actions

in response to certain fire scenarios that would result in a loss of circuit breaker

coordination and could initiate secondary fires in plant locations outside of the initial fire

area.

Description. Procedure OFN KC-016, Fire Response, Revision 19, specified operator

actions to be taken in response to fires outside of the control room. This procedure

provided the mitigating actions needed to maintain the reactor in hot standby in the

event of various failures and spurious actuations. The inspectors identified the following

13 fire areas where the prescribed mitigating actions would remove electrical circuit

protection (i.e., circuit breaker coordination) for the train affected by the fire and could

initiate secondary fires in plant locations outside of the initial fire area:

Fire Area A-8

Auxiliary Building - 2000 Elevation, General Area

Fire Area A-11

Cable Chase (Room 1335)

Fire Area A-16

Auxiliary Building - 2026 Elevation, General Area

Fire Area A-17

South Electrical Penetration (Room 1409)

Fire Area A-18

North Electrical Penetration (Room 1410)

Fire Area C-18

North Vertical Cable Chase (Room 3419)

Fire Area C-21

Lower Cable Spreading (Room 3501)

Fire Area C-22

Upper Cable Spreading (Room 3801)

Fire Area C-23

South Vertical Cable Chase (Room 3505)

Fire Area C-24

North Electrical Chase (Room 3504)

Fire Area C-30

South Vertical Cable Chase (Room 3617)

Fire Area C-33

South Vertical Cable Chase (Room 3804)

Fire Area RB

Reactor Building (Containment)

For these fire areas, the procedure directed the operators to remove power to a

power-operated relief valve if a fire caused the power-operated relief valve to spuriously

open and operators could not close its associated block valve. Specifically, the

procedure directed the operators to open circuit breakers on the associated 125 Vdc

power supply. The inspectors noted that the failure of the block valve to close resulted

from fire damage and not from a spurious operation of the valve.

The licensee specified this action in order to close the power-operated relief valve and

preclude the potential for spurious opening due to inter-cable faults (i.e., cable-to-cable

hot shorts). However, the inspectors determined this action would also remove the

control power used to operate 4160 Vac and 480 Vac circuit breakers. The removal of

- 73 -

Enclosure 2

control power would prevent remote breaker operations and disable the circuit breaker

protective trips for the train affected by the fire.

Removing control power to the circuit breaker results in a loss of its ability to

automatically isolate faults before severe damage occurs. As a result, fire-induced faults

(shorts to ground) in non-essential power cables of the affected 4160 Vac and 480 Vac

supplies may not clear until after tripping an upstream feeder breaker to the supplies,

which would remove power from equipment that was assumed by the safe shutdown

analysis to be unaffected. This action would also prevent breakers from automatically

opening during an overload condition and could initiate secondary fires in plant locations

outside of the initial fire area.

The safe shutdown analysis assumed that a fire occurred in one fire area at any time.

The inspectors determined that the mitigating actions taken in response to fires in the

listed fire areas had the potential to initiate secondary fires in other plant locations, which

would invalidate the safe shutdown analysis and could impact the ability to achieve and

maintain safe shutdown.

Analysis. Prescribing mitigating actions in response to certain fire scenarios that would

result in a loss of circuit breaker coordination and could initiate secondary fires in plant

locations outside of the initial fire area was a performance deficiency. The inspectors

determined that this deficiency was more than minor because it was associated with the

Protection Against External Factors 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.

The significance of this finding was evaluated using the Significance Determination

Process in Manual Chapter 0609, Appendix F, Fire Protection Significance

Determination Process, because it affected fire protection defense-in-depth strategies

involving post-fire safe shutdown systems.

The inspectors associated the finding with the post-fire safe shutdown category since the

performance deficiency would remove power from equipment that was assumed by the

safe shutdown analysis to be unaffected and could initiate secondary fires in plant

locations outside of the initial fire area. The inspectors assigned the finding a high

degradation rating since the affected circuit breakers would not provide any fire

protection benefit and would receive no fire protection credit.

The inspectors performed a Phase 2 evaluation to determine an upper limit for the

change in core damage frequency. The inspectors determined eight credible fire

scenarios that could result in core damage under certain conservative assumptions. The

pertinent parameters and results of these scenarios are summarized below.

Attachment B provides a more detailed discussion of the Phase 2 evaluation.

- 74 -

Enclosure 2

Table 1. Phase 2 Evaluation Results

Scenario

Number

Ignition

Source

Source

Description

(Fire Area)

Fire

Ignition

Frequency

Heat

Release

Rate

Severity

Factor

Probability of

Non-Suppression

Probability

of a Hot

Short

CCDP

1

RP-333

Relay

Panel

(A-16)

6.00E-5

200 kW

0.9

0.35

0.02

3.78E-7

2

RP-333

Relay

Panel

(A-16)

6.00E-5

650 kW

0.1

0.35

0.02

4.20E-8

3

SK194B

Security

Panel

(A-16)

6.00E-5

200 kW

0.1

0.35

0.02

4.20E-8

4

NG01B

600V MCC

(A-18)

6.00E-5

200 kW

0.1

0.44

0.02

5.28E-8

5

Transient

Fire

C-21

6.26E-6

70 kW

0.9

0.26

0.02

2.93E-8

6

Transient

Fire

C-21

6.26E-6

200 kW

0.1

0.26

0.02

3.26E-9

7

Transient

Fire

C-22

5.54E-6

70 kW

0.9

1.00

0.02

9.96E-8

8

Transient

Fire

C-22

5.54E-6

200 kW

0.1

1.00

0.02

1.11E-8

Total

6.58E-7

In each of these scenarios, the conditional core damage probability (CCDP) bounds the

change in core damage frequency. The inspectors calculated the conditional core

damage probability using the following equation:

Short

Hot

n

Suppressio

Non

P

x

P

x

SF

x

FIF

CCDP

=

where:

FIF denotes the fire ignition frequency

SF denotes the severity factor

n

Suppressio

Non

P

denotes the non-suppression probability

- 75 -

Enclosure 2

Short

Hot

P

denotes the probability of a hot short

The sum of the conditional core damage probabilities for each of the fire scenarios

bounded the total change in core damage frequency associated with this performance

deficiency. Since the change in core damage frequency exceeded1E-7, the inspectors

screened the finding for its potential risk contribution to a large early release frequency.

In accordance with the guidance in NRC Inspection Manual Chapter 0609, Appendix H,

the inspectors determined this finding did not involve a significant increase in the risk of

a large early release of radiation because Wolf Creek has a large, dry containment and

the accident sequences contributing to a change in the core damage frequency did not

involve either a steam generator tube rupture or an intersystem loss of coolant accident.

Since this bounding change in core damage frequency was less than 1E-6/year and the

finding did not involve a significant increase in the risk of a large early release frequency,

the inspectors determined this performance deficiency had very low risk significance

(Green). This finding was not assigned a cross-cutting aspect because it existed more

than two years and does not represent current performance.

As a compensatory measure, the licensee implemented an hourly fire watch in the

affected fire areas, with the exception of the reactor building, which is not readily

accessible during power operations. For the reactor building, the licensee is monitoring

the containment temperature as a compensatory measure.

Enforcement. License Condition 2.C.(5) states, in part, that the licensee shall maintain

in effect all provisions of the approved fire protection program as described in the

Standardized Nuclear Unit Power Plant System (SNUPPS) 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 Wolf

Creek Updated Safety Analysis Report combined the SNUPPS Final Safety Analysis

Report, Revision 17, and the Wolf Creek Site Addendum, Revision 15, into one

document.

Appendix 9.5B of the Updated Safety Analysis Report provides an area-by-area analysis

of the power block that incorporated Drawing E-1F9905, Fire Hazards Analysis,

Revision 2, by reference. Drawing E-1F9905 states that the overall intent is to

demonstrate that a single plant fire will not negatively affect the post-fire safe shutdown

capability and that if a circuit damaged by a fire is protected by an individual overcurrent

protection device, that device is assumed to function to clear the fault.

Contrary to the above, prior to December 22, 2009, the licensee failed to implement and

maintain in effect all provisions of the approved fire protection program. Specifically, the

licensee prescribed mitigating actions in response to certain fire scenarios that would

result in a loss of circuit breaker coordination (i.e., disable an overcurrent protection

device from functioning to clear a fault) and could initiate secondary fires in plant

locations outside of the initial fire area that negatively affect the post-fire safe shutdown

capability. However, the plants post-fire safe shutdown capability only evaluated

damage resulting from a single fire.

- 76 -

Enclosure 2

The licensee entered this issue into their corrective action program as Performance

Improvement Request 2008-005210. Because this violation was of very low safety

significance and it was entered into the corrective action program, this violation is being

treated as a non-cited violation, consistent with the NRC Enforcement Policy:

NCV 05000482/2009005-16, Operator Actions Disable Circuit Breaker Coordination and

Could Initiate Secondary Fires.

.4

(Closed) Unresolved Item 05000482/2008010-01: Post-fire Safe Shutdown Inspection

Did Not Identify Diagnostic Information

During a triennial fire protection inspection in 2008, the inspectors identified an

unresolved item concerning the availability of diagnostic instrumentation needed to

respond to a loss of reactor coolant pump seal cooling during certain fire scenarios. The

plant design uses reactor coolant pump seal injection and thermal barrier cooling to cool

the reactor coolant pump seals. One method of seal cooling must be maintained during

reactor coolant pump operation to prevent seal failure, which, in some cases, could lead

to increased seal leakage beyond the capacity of the charging pump.

The licensee identified that fire damage in four fire areas could isolate both methods of

seal cooling. The inspectors identified that the licensee relied upon a decrease in

pressurizer level to diagnose a loss of seal cooling. The inspectors determined the fire

response procedure was inadequate since pressurizer level would not decrease until

after seal failure occurred. Since the procedure required operators to recognize the loss

of cooling and take response actions and the procedure did not identify adequate

instrumentation to be used, the inspectors could not verify that it would remain free of

fire damage for fires in these four fire areas.

In response to the unresolved item, the licensee determined the instrumentation that

would be available to diagnose a loss of seal cooling for fires in these four areas. The

licensee determined that the thermal barrier flow switches and alarms would remain

available for all four areas. The licensee also determined that seal injection flow and

temperature would remain available for most, if not all, of the trains for each fire area.

The inspectors reviewed the abnormal operating procedures used in the event of reactor

coolant pump problems. Based on this review and the licensees analysis of available

instrumentation, the inspectors concluded that it was reasonable to believe that

operators had sufficient instrumentation and guidance to promptly recognize, diagnose,

and respond to a loss of reactor coolant pump seal cooling.

The failure to establish written procedures adequately implementing the approved fire

protection program was a performance deficiency and a violation of Technical

Specification 5.4.1.d. The inspectors determined this performance deficiency was of

minor safety significance since it was not similar to any example in Manual

Chapter 0612, Appendix E, nor did it meet any of the minor questions in Manual

Chapter 0612, Appendix B. This performance deficiency constitutes a violation of minor

significance that is not subject to enforcement action in accordance with the NRCs

Enforcement Policy.

- 77 -

Enclosure 2

The licensee implemented an hourly fire watch as an immediate compensatory measure

and entered this issue into their corrective action program as Condition

Report 2008-005171.

.5

(Closed) Licensee Event Report 05000482/2008006-00: Entry Into Mode 4 Without An

Operable Containment Spray System

On July 3, 2008, Wolf Creek submitted LER 2008006 which described missed VT-2 weld

inspections when modifying train B containment spray recirculation line in refueling

outage 16. Wolf Creek stated that changes to shim the recirculation line inadvertently

resulted in missing the VT-2 post-maintenance test. This resulted in ascending to Mode

4 without an operable containment spray system. Wolf Creek identified this issue on

May 8, 2008, at 1:45am and entered Technical Specification 3.6.6 while in Mode 4. The

VT-2 inspections were performed satisfactorily and Technical Specification 3.6.6 was

exited at 3:13am on May 8, 2008. Enforcement aspects are discussed in Section 4OA7.

This LER is closed.

.6

(Closed) Licensee Event Report 05000482/2008-08-00, -01, -02: Potential for Residual

Heat Removal Trains to be Inoperable during Mode Change.

All three revisions of this licensee event report were discussed and enforcement action

was taken in NRC Inspection Report 05000482/2009006. This licensee event report is

closed.

.7

(Closed) Unresolved Item 2008005-02: Residual Heat Removal Suction Piping

Saturation Temperature and Pressure.

This unresolved item was inspected and enforcement action was taken in NRC

Inspection Report 05000482/2009006. This unresolved item is closed.

.8

(Closed) Licensee Event Report 05000482/2008-004-01: Loss of Power Event When

the Reactor was Defueled.

Licensee Event Report 05000482/2008-004-00 was closed in NRC Inspection

Report 05000482/2008004 as a Green finding. In NRC Inspection

Report 05000482/2009004, the inspectors identified a violation of 10 CFR 50.73

associated with this event report. Wolf Creek subsequently submitted revised Licensee

Event Report 2008-004-01 in response to the Severity Level IV violation. The submittal

of Licensee Event Report 05000482/2008-004-01 restores compliance with

10 CFR 50.73. This licensee event report is closed.

4OA6 Meetings

Exit Meeting Summary

On October 22, 2009, the radiation protection inspectors presented the inspection results

to Mr. M. W. Sunseri and other members of the licensee staff. The licensee

- 78 -

Enclosure 2

acknowledged the issues presented. The inspector asked the licensee whether any

materials examined during the inspection should be considered proprietary. No

proprietary information was identified.

On October 30, 2009, the in-service inspection inspectors debriefed the inspection

results to Mr. M. W. Sunseri, and other members of the licensee staff. The licensee

acknowledged the issues presented. The inspectors acknowledged review of proprietary

material during the inspection which had been or will be returned to the licensee.

On December 17 and 22, the fire protection inspectors conducted telephonic exit

meetings and presented the results of the staffs closure of fire protection unresolved

items. The inspectors presented the results to L. Ratzlaff, Manager Support

Engineering, on December 17 and M.W. Sunseri, on December 22. The licensee

acknowledged the issues presented. The inspectors asked the licensee whether any of

the material examined during the inspection should be considered proprietary. No

proprietary information was identified.

On January 14, 2010, the resident inspectors presented the inspection results of the

resident inspections to Mr. M.W. Sunseri, and other members of the licensee's

management staff. The licensee acknowledged the findings presented. The inspectors

noted that while proprietary information was reviewed, none would be included in this

report.

4OA7 Licensee-Identified Violations

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

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

Enforcement Policy, NUREG-1600, for being dispositioned as noncited violations.

.1

On October 22, 2009, at 12:06 p.m., the Wolf Creek control room received trouble

annunciators for emergency diesel generator A. Emergency diesel generator B was out

of service for planned maintenance. 10 CFR 50.47(b)(4) requires that a standard

emergency classification action level scheme be used by the licensee. Wolf Creek

EAL 6, Loss of Electrical Power/Assessment Capability, requires, in part, that when

both emergency diesel generators are out of service for greater than 15 minutes, a

Notice of Unusual Event be declared. Contrary to the above, on October 22, 2009, Wolf

Creek did not declare a Notice of Unusual Event until 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after both emergency

diesel generators were out of service. This issue is of very low safety significance

(Green) because it is associated with failure to report a Notification of Unusual Event.

Wolf Creek initiated Condition Report 21058 regarding the late declaration.

.2

On July 3, 2008, Wolf Creek submitted Licensee Event Report LER 2008006 which

described missed VT-2 weld inspections when modifying train B containment spray

recirculation line in Refueling Outage 16, requiring the train to be declared inoperable.

This issue has been entered in to the corrective action program as Condition

Report 2008-2197. Technical Specification 3.0.4, states, in part, that when a limiting

condition of operation is not met, that mode changes shall only be made: when actions

to be entered permit continued operation for an unlimited period of time, after a risk

- 79 -

Enclosure 2

assessment, or when an allowance is stated in the specification. Technical Specification

Limiting Condition of Operation 3.6.6 requires, in part, two operable trains of

containment spray in Modes 1 through 4. Contrary to the above, on May 8, 2008, Wolf

Creek entered Mode 4 with only one operable containment spray system. This issue is

of very low safety significance (Green) because there was no loss of function of the

containment spray system.

A-1

Attachment 1

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. D. Benham, Integrated Plant Scheduling

T. D. Card, Engineering

B. E. Dale, Manager Maintenance

T. M. Damashek, Superintendent, Operations Support

T. F. East, Manager, Emergency Planning

D. L. Fehr, Manager Information Systems

R. L. Gardner, Manager, Quality

S. E. Hedges, Vice President Oversight

D. M Hooper, Supervisor Licensing

J. K. Kent, Finance Management

W. R. Ketchum, Supervisor, Plant Safety Assessment

S. R. Koenig, Corrective Actions

W. T. Muilenburg, Licensing

P. J. Bedgood, Superintendent, Chemistry/Radiation Protection

C. L. Palmer, Major Modifications

J. M. Pankaskie, Supervisor, Design Engineering

E. M. Peterson, Ombudsman

D. Phelps, Owners Representative

B. Poteat, Piedmont

L. Ratzlaff, Manager, Support Engineering

E. A. Ray, Manager Chemistry/Health Physics

K. Scherich, Director Engineering

A. F. Stull, Vice President & Chief Administrative Officer

M. W. Sunseri, President and Chief Executive Officer

B. J. Vickery, Supply Chain

B. Walters, Supervisor, Security

M. J. Westman, Manager, Training

K. Frederickson, Licensing

J. Suter, Fire Protection

NRC Personnel

D. Loveless, Senior Reactor Analyst

A-2

Attachment 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed 05000482/2009005-02

NCV

Control of Transient Ignition Sources (Section 1R05)05000482/2009005-03

NCV

Failure to Identify Sources of Boron Leakage

(Section 1R08)05000482/2009005-04

NCV

Failure to Incorporate Requirements of Regulatory

Guide 1.182 into Daily Shutdown Risk Assessment

(Section 1R13.1)05000482/2009005-05

NCV

Mode Change Under Technical Specification 3.0.4.b

Without Required Risk Management Actions

(Section 1R13.2)05000482/2009005-06

NCV

Failure to Follow Corrective Action Procedure

(Section 1R13.3)05000482/2009005-07

NCV

Failure to Follow Procedure Results in Draining of

Emergency Core Cooling System Pump Oil

(Section 1R13.4)05000482/2009005-08

NCV

Inadequate Operability Evaluation of Essential Service

Water Pumps (Section 1R15.1)05000482/2009005-09

NCV

Positive Reactivity Addition Prohibited by Technical

Specifications while in Mode 2 (Section 1R15.2)05000482/2009005-10

NCV

Failure to Obtain Vendor Data Necessary for Plant

Modification (Section 1R18)05000482/2009005-12

NCV

Unevaluated Scaffold Against Component Cooling Water

Piping (Section 1R20)05000482/2009005-13

NCV

Failure to Maintain Administrative Control of Keys to

Locked High Radiation Areas (Section 2SO1)05000482/2009005-14

NCV

Failure to Identify Inoperable P-6 Interlock and

Intermediate Range Detector (Section 4OA2)05000482/2009005-15

NCV

Failure to Report a Condition that Could Have Prevented

Fulfillment of a Safety Function (Section 4OA3)05000482/2009005-16

NCV

Operator Actions disable Circuit Breaker Coordination and

Could Initiate Secondary Fires (Section 4OA5.1)

A-3

Attachment 1

Opened 05000482/2009005-01

VIO

Failure to Correct Discolored Boric Acid Deposits

(Section 1R05)05000482/2009005-11

VIO

Failure to Correct Vessel Head Vent Path (Section 1R20)

Discussed 05000482/2009002-07

VIO

Failure to correct component cooling water valve closures

(EA-09-110) (Section 1R18)

05000482/2009-005-00

LER

Loss of both Diesel Generators with all fuel in the Spent

Fuel Pool (Section 4OA3)

Closed 05000482/2008010-01

URI

Post Fire Safe Shutdown Procedure Did Not Identify

Diagnostic Information (Section 4OA5.4)05000482/2008010-04

URI

Operator Actions May Create the Potential for Secondary

Fires (Section 4OA5.3)

05000482/2008-006-00

LER

Entry Into Mode 4 Without An Operable Containment

Spray System (4OA5.5)

05000482/2008-008-00

05000482/2008-008-01

05000482/2008-008-02

LER

Potential for Residual Heat Removal Trains to be

Inoperable during Mode Change (Section 4OA5.6)05000482/2008005-02

URI

Residual Heat Removal Suction Piping Saturation

Temperature and Pressure (Section 4OA5.7)

05000482/2008-004-01

LER

Loss of Power Event When the Reactor was Defueled

(Section 4OA5.8)

LIST OF DOCUMENTS REVIEWED

Section 1RO1: Adverse Weather Protection

MISCELLANEOUS

NUMBER

TITLE

REVISION

FL-01

Flooding of Auxiliary Building

01

CR 22801

Auxiliary Building Flooding Question

3.4.1

Updated Safety Analysis Report, Flood Protection

19

A-4

Attachment 1

Section 1RO4: Equipment Alignment

PROCEDURES

NUMBER

TITLE

REVISION

M-12EC01

Fuel Pool Cooling and Clean-up System

19

SYS EC-120

Fuel Pool Cooling and Clean-up System Startup

44

CKL EC-120

Fuel Pool Cooling and Clean-up System Normal

Valve Lineup/Breaker Checklist

14A

CKL JE-120

Emergency Fuel Oil System Lineup

19

STS NB-005

Breaker Alignment Verification

18

CKL KJ-121

Diesel Generator NE01 and NE02 Valve Checklist

28A

FPPM-015

Fuel Building Elevation 2000

7

Section 1RO5: Fire Protection

PROCEDURES

NUMBER

TITLE

REVISION

FPPM-009

Control Bldg El. 2000

2

AP 10-106

Fire Preplans

7

Fppm-015

Fuel Building Elevation 2000

7

Section 1RO6: Flood Protection Measures

MISCELLANEOUS

NUMBER

TITLE

ALR 00-095C

AFP Sump Room Level Hi

FL-14

Feed Pump Room Maximum Flood Level

LE-M-002

Auxiliary Building Room 1206, 1207 Maximum Flood

Level

WORK ORDER

WO 08-304475-000

A-5

Attachment 1

Section 1RO7: Heat Sink Performance

PROCEDURES

NUMBER

TITLE

REVISION

STN PE-038

Containment Cooler Performance Test

10

EPRI NP-7552

Heat Exchanger Performance Monitoring Guidelines

1991

Section 1RO8: Inservice Inspection Activities

CONDITION REPORTS

00003599

00011297

00011954

00018217

00018785

00019248

00020993

00021274

2008-004840

CONDITION REPORT GENERATED FOR THIS INSPECTION

00020993, Fire Watches

DRAWINGS

NUMBER

TITLE

REVISION

E 11173-171-005

Westinghouse Electric corporation General Arrangement

Plan

001

E 11373-101-005

Westinghouse Electric Corporation Closure Head

Assembly

002

E 1455E85,

Sheet 1

Westinghouse Electric Corporation Closure Head (SAP)

General Assembly

001

E 6467E69

Wolf Creek Simplified Head Assembly Radiation Shield

Assembly

006

M 164-00043

Mirror Insulation

W008

M-189-50EJ-02-04

Residual Heat Removal B Train RHR Pump Suction

00

PROCEDURES

NUMBER

TITLE

REVISION

AI 16F-001

Evaluation of Boric Acid Leakage

5

AI 16F-002

Boric Acid Leakage Management

5

AP 16F-001

Boric Acid Corrosion Control Program

5

A-6

Attachment 1

NUMBER

TITLE

REVISION

29A-003

Steam Generator Management

AP-10-100

Fire Protection Program

14

AP-10-101

Control of Transient Ignition Sources

12

AP-10-102

Control of Combustible Materials

13

AP-21I-001

Temporary Modification

8

APF 28D-001

Self-Assessment Process

11

PDI-ISI-254-SE-

NB

Remote Inservice Examination of Reactor Vessel

Nozzle to Safe End, Nozzle to Pipe, and Safe end to

Pipe Welds Using the Nozzle Scanner

1

PDI-UT-1

PDI Generic Inspection Procedure for the Ultrasonic

Examination of Ferritic Pipe Welds

D

PDI-UT-2

PDI Generic Inspection Procedure for the Ultrasonic

Examination of Austenitic Pipe Welds

C

PDI-UT-6

PDI Generic Inspection Procedure for the Ultrasonic

Examination of Reactor Pressure Vessel Welds

F

QCP-20-501

PT

8

QCP-20-502

MT

8

QCP-20-503

UT Thickness-Wall Thin

3

QCP-20-504

UT For Flaw Detection

5

QCP-20-508

RT Welds and Components

4

QCP-20-510

Ultrasonic Instrument Linearity Verification

3

QCP-20-511

RT of AWS Groove Welds

1B

QCP-20-514

ET Testing

5B

QCP-20-516

PT/NON-STD Temp

05

QCP-20-517

RT Wall Thinning

2A

QCP-20-521

UT Profile and Plotting

1B

QCP-20-522

Ultrasonic Examination of Ferritic Piping Welds

1B

QCP-20-523

Ultrasonic Examination of Austenitic Piping Welds

1B

QCP-20-527

UT- Soldering

1

QCP-20-540

VT-1 Exam

0B

QCP-20-541

VT-3 Exam

2

QCP-20-543

Fluorescent Dye PT Exam

1

A-7

Attachment 1

NUMBER

TITLE

REVISION

SG-CDME-08-15

Wolf Creek RF16 Condition Monitoring Assessment and

Operational Assessment, April 2008

1

SG-SGMP-09-9

Steam Generator Degradation Assessment for Wolf

Creek, RF17 Refueling Outage, October 2009

0

STN PE-040D

RCS Pressure Boundary Integrity Walkdown

3

STN PE-040G

Transient Event Walkdown

0

STS PE-040E

RPV Head Visual Inspection

2

UT-95

Ultrasonic Examination of Austenitic Piping Welds

3

WCRE-18

Boric Acid Corrosion Control Program Plan

1

WORK ORDERS

08-304695-000

09-313385-000

09-320908-000

09-320918-000

08-310117-000

09-318982-001

09-320910-000

09-320918-001

08-310119-000

09-319416-002

09-320910-001

09-320919-000

08-310136-000

09-320490-000

09-320911-000

09-321389-000

08-311159-000

09-320505-000

09-320912-000

08-311161-000

09-320891-000

09-320913-000

WORK REQUESTS

09-076556

09-076676

09-076711

09-076707

09-076561

09-076307

09-076705

09-076712

09-076710

09-076706

MISCELLANEOUS

NUMBER

TITLE

REVISION / DATE

Steam Generator data Analysis Desktop

Instruction

4

SGAMP Self Assessment, Steam Generator Asset

Management Program

October 17, 2008

Boric Acid Corrosion Control Program 2009 3rd

Quarter Inspection/Monitoring Report

October 13, 2009

A-8

Attachment 1

NUMBER

TITLE

REVISION / DATE

Boric Acid Leakage Screening/Evaluation for

Component EMHV8888

October 8, 2008

Boric Acid Leakage Screening/Evaluation for

Component BGHCV0182

January 5, 2009

Boric Acid Leakage Screening/Evaluation for

Component EP8956C

October 19, 2009

Boric Acid Leakage Screening/Evaluation for

Component EMHV8924

October 20, 2009

Boric Acid Leakage Screening/Evaluation for

Component BBPV8702A

October 14, 2009

Boric Acid Leakage Screening/Evaluation for

Component BGHCV0128

July 9, 2009

Boric Acid Leakage Screening/Evaluation for

Component EMV0175

April 8, 2009

Boric Acid Leakage Screening/Evaluation for

Component BBC5413

April 7, 2009

Boric Acid Leakage Screening/Evaluation for

Component HETCV0250

January 13, 2009

Boric Acid Leakage Screening/Evaluation for

Component ECV0048

January 13, 2009

Boric Acid Leakage Screening/Evaluation for

Component ECV0157

January 12, 2009

Boric Acid Leakage Screening/Evaluation for

Component BBHV8351B

January 12, 2009

Boric Acid Leakage Screening/Evaluation for

Component EJ8730A

January 12, 2009

Boric Acid Leakage Screening/Evaluation for

Component EJV0128

January 12, 2009

Boric Acid Leakage Screening/Evaluation for

Component EJFE0619

January 12, 2009

Boric Acid Leakage Screening/Evaluation for

Component BG8405A

January 9, 2009

Boric Acid Leakage Screening/Evaluation for

Component ENV0115

January 9, 2009

Boric Acid Leakage Screening/Evaluation for

Component BGV0526

January 8, 2009

A-9

Attachment 1

NUMBER

TITLE

REVISION / DATE

Boric Acid Leakage Screening/Evaluation for

Component BBV0357

January 5, 2009

Boric Acid Leakage Screening/Evaluation for

Component BGFCV0110A

January 59, 2009

Boric Acid Leakage Screening/Evaluation for

Component BBV0007

October 15, 2009

Ultrasonic Instrument Calibration Data Record and

Certification for Panametrics, Epoch 4,

SN 081574401

September 2, 2009

Transducer Certification for Krautkramer, 113-222-

591, SN 00V0JM

April 26, 2002

Transducer Certification for Krautkramer, 113-222-

591, SN 00V49N

May 16, 2002

Thermometer Certification for PTC, 312F,

SNs 265095, 265109, 265113

January 6, 2009

Krautkramer Transducer Certification, 113-224-

5591, SN SC0123

January 11, 2008

Krautkramer Transducer Certificate of Conformity,

113-234-591, SN SD0172

December 3, 2007

Ultrasonic Instrument Calibration Data Record and

Certification for Krautkramer, USN 60 SW, SN

01R5NW

August 24, 2009

APF 28D-001-02

Self Assessment Report SEL 04-038 , Steam

Generator Program

4

APF-10-102-01

Transient Combustible Materials Permit

3

AWJ003

Ultrasonic Calibration/Examination Sheet for RPV

Meridonal Weld, ISI Number CH-101-104-C

October 22, 2009

AWJ004

Ultrasonic Calibration/Examination Sheet for RPV

Meridonal Weld, ISI Number CH-101-104-B

October 22, 2009

ET 05-0014

Docket 50-482: 10 CFR 50.55a Request Number

I3R-03 for the Third Ten-Year Interval Inservice

Inspection (ISI) Program - Request for Relief to

Allow Use of Alternate Requirements for Snubber

Inspection and Testing

September 28, 2005

ET 06-0010

Docket 50-482: Inservice Inspection Program Plan

for the Third Ten-Year Interval and 10 CFR 50.55a

Requests I3R-01, I3R-02, and I3R-04

March 2, 2006

A-10

Attachment 1

NUMBER

TITLE

REVISION / DATE

ET 06-0021

Docket No. 50-482: 10 CFR 50.55a Request I3R-

05, Installation and Examination of Full Structural

Weld Overlays for Repairing/Mitigating Pressurizer

Nozzle-to-Safe End Dissimilar Metal Welds and

Adjacent Safe End-to-Piping Stainless Steel Welds

May 19. 2006

ET 06-0042

Docket 50-482: Wolf Creek Nuclear Operating

Corporations Response to the September 20,

2006 NRC Request for Additional Information

Regarding 10 CFR 50.55a Request I3R-05

September 27, 2006

ET 06-0043

Docket 50-482: Wolf Creek Nuclear Operating

Corporations Response to NRC Request for

Additional Information Regarding 10 CFR 50.55a

Request I3R-01

October 5, 2006

ET 06-0044

Docket 50-482: Wolf Creek Nuclear Operating

Corporations Revised Commitment Regarding 10

CFR 50.55a Request I3R-05

October 2, 2006

ET 06-0058

Docket No. 50-482: Wolf Creek Nuclear Operating

Corporations Response to the Second NRC

Request for Additional Information Regarding 10

CFR 50.55a Request I3R-01

December 20, 2006

ET 08-0044

Docket No. 50-482: 10 CFR 50.55a Request I3R-

06, Alternative to Examination Requirements of

ASME Section XI for Class 1 Piping Welds

Examined from the Inside of the Reactor Vessel

September 16, 2008

ET 09-0016

Docket No. 50-482: Revision to Technical

Specifications 5.5.9, Steam Generator (SG)

Program, and TS 5.6.10, Steam Generator Tube

Inspection Report, for a Permanent Alternate

Repair Criterion

June 2. 2009

ET 09-0021

Docket No. 50-482: Response to Request for

Additional Information Related to License

Amendment Request for a Permanent Alternate

Repair Criterion to Technical Specification 5.5.9,

Steam Generator (SG) Program

August 25, 2009

ET 09-0023

Docket No. 50-482: Response to Request for

Additional Information Related to License

Amendment Request for a Permanent Alternate

Repair Criterion to Technical Specification 5.5.9,

Steam Generator (SG) Program

September 3, 2009

A-11

Attachment 1

NUMBER

TITLE

REVISION / DATE

ET 09-0024

Docket No. 50-482: Response to Request for

Clarifications in Response to Application for

Withholding Proprietary Information from Public

Disclosure (TAC NO. ME1393)

September 3, 2009

ET 09-0025

Docket No. 50-482: Revision to Technical

Specification (TS) 5.5.9, Steam Generator (SG)

Program, and TS 5.6.10, Steam Generator Tube

Inspection Report

September 15, 2009

I-ENG-023

Steam Generator Data Analysis Guidelines

8

JEW014

Ultrasonic Calibration/Examination Sheet for RHR

Pipe to Pipe Weld , ISI Number EJ-04-F019

October 22, 2009

JEW015

Ultrasonic Calibration/Examination Sheet for

SI/HPCI Pipe to Elbow Weld, ISI Number EM-03-

S015-B

October 22, 2009

M-12KJ04

Piping and Instrumentation Diagram Standby

Diesel Generator B Lube Oil System

13

M-12KJ06

Piping and Instrumentation Diagram Standby

Diesel Generator B Lube Oil System

13

M-13EF08

Piping Isometric Essential Service Water- Diesel

Generator Bldg.

1

QCF 20-510-01

Ultrasonic Instrument Linearity Form

2

QCF-20-100-01

Contractor Certification Review

2

QCF-20-504-02

Ultrasonic Flaw Detection Data Sheet

2

QCF-20-504-06

Ultrasonic Flaw Detection Calibration Data Sheet

0

SAP-+PT-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-+PTUB-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-01-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-02-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-03-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-04-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

A-12

Attachment 1

NUMBER

TITLE

REVISION / DATE

SAP-05-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-06-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-07-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-08-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-09-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-10-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-11-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-12-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-BOB-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-DELTA-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SAP-GHENT-09

Steam Generator Eddy Current Inspection Multi-

Frequency Eddy Current Parameters

0

SEL 04-038

Steam Generator Program

4

SG-CDME-08-15

Wolf Creek RF16 Condition Monitoring

Assessment and Operational Assessment, April

2008

1

SG-CDME-09-1

Wolf Creek Steam Generator Secondary Side

Condition Monitoring and Operational Assessment

for Fuel Cycle and Refueling Outage 17

0

SG-SGMP-09-9

Steam Generator Degradation Assessment for

Wolf Creek, RF17 Refueling Outage, October 2009

0

WDI-LTR-

ENG-09-0016

Technical Justification of the Impact of Using

Tap/Demineralized Water for UT System

Calibration and Borated Reactor Cavity Water for

RVISI UT Examinations.

0

A-13

Attachment 1

Section 1R12: Maintenance Effectiveness

MISCELLANEOUS

NUMBER

TITLE

REVISION /

DATE

EG-01

Maintenance Rule Database - Component Cooling

Water - Engineered Safety Features System Cooling

n/a

EG-03

Maintenance Rule Database - Component Cooling

Water System - RCP Thermal Barrier Cooling

n/a

EG-07

Maintenance Rule Database - Component Cooling

Water System - ESW Frazil Ice Prevention

n/a

M-11EG02

System Flow Diagram Component Cooling Water

System

2

M-762-001-02

Nuclear Instrumentation System Source Range N-31

Functional Block Diagram

7

PIR 2004-1625

Two Source Range Channels are Required to

Perform Core Alterations During a Refueling Outage

June 22,

2004

SE-01

Maintenance Rule Database - Source Range

Nuclear Instrumentation

n/a

SE-02

Maintenance Rule Database - Intermediate Range

Nuclear Instrumentation

n/a

OFN PK-029

Loss of Non-Vital 125 VDC Bus PK01, PK02, PK03,

PK4, and Annunciators

15

STS IC-232

Channel Operational Test Nuclear Instrumentation

System Source Range N-32 Protection Set II

15

AI 28A-023

Evaluation of Maintenance Rule Functional Failure

1

AP 23M-001

WCGS Maintenance Rule Program

7

EDI 23M-050

Establishing Performance Criteria for Structures,

Systems and Components with the Scope of the

Maintenance Rule

3

WCN-7328

Report on ECAD Testing at Wolf Creek Generating

Station

October 28,

2009

WR 5047865

Functional Failure Determination (EDI 23M-050)

April 24,

2005

Maintenance Rule Expert Panel Meeting Minutes

February 18

, 1999

A-14

Attachment 1

NUMBER

TITLE

REVISION /

DATE

Maintenance Rule Expert Panel Meeting Minutes

April 10,

2000

Maintenance Rule Expert Panel Meeting Minutes

April 24,

2000

WORK ORDERS

NUMBER

TITLE

REVISION /

DATE

WO 07-293925-000

Replace Electrolytic Capacitors or Replace Power

Supply NIS Source Range Hi Voltage Power Supply

March 31,

2008

WO 08-302634-000

Perform STN IC-031 Source Range N-31 High Flux

at Shutdown Alarm Calibration

January 12,

2008

WO 08-302635-000

Perform STN IC-032 Source Range N-32 High Flux

at Shutdown Alarm Calibration

January 12,

2008

WO 08-305403-000

Refuel 16 Perform STN IC-031 Source Range N-31

High Flux at Shutdown Alarm Calibration

April 11,

2008

WO 08-305404-000

Refuel 16 Perform STN IC-032 Source Range N-32

High Flux at Shutdown Alarm Calibration

April 11,

2008

WO 08-310573-000

Replace Electrolytic Capacitors or Replace Power

Supply

August 13,

2009

WO 09-314187-000

Retorque CCW Pump to Motor Coupling Bolts

February

12, 2009

WO 09-316487-000

Troubleshoot IR SE NI-36 to Determine Why it Hung

Up Following RX Trip on 4/28 and Repair as

Necessary

April 28,

2009

WO 09-318691-000

Troubleshoot CCW Return from RCP Thermal

Barrier High Flow Setpoint

September

22, 2009

WO 09-320716-000

Refuel 17. Perform Detector and Cable Integrity

Checks for SR, IR, and PR NIS Channels

October 10,

2009

WO 09-320874-000

Troubleshoot Source Range Channel 31 to

Determine Why it Failed After it was Energized

October 10,

2009

WO 09-320874-001

Replace High Voltage Power Supply (NQ101) in

N-31 Source Range during partial STS IC-431

October 10,

2009

WO 09-320874-005

Replace R150 in N-31

October 10,

2009

A-15

Attachment 1

NUMBER

TITLE

REVISION /

DATE

WR 09-076482

During the Performance of STS IC-432 the Two-Phi

Meter Failed to Alarm Annunciator

October 24,

2009

WORK ORDERS

WO 05-270366-000

WO 05-270366-006

WO 06-288260-000

CONDITION REPORTS

CR 20052

CR 01880

Section 1R13: Maintenance Risk Assessment and Emergent Work Controls

MISCELLANEOUS

NUMBER

TITLE

REVISION /

DATE

AP 22B-001

Outage Risk Management

11

AP 22C-003

Operational Risk Assessment Program

14A

AP 23M-001

WCGS Maintenance Rule Program

7

APF 22B-001-02

Daily Shutdown Risk Assessments for RFO 17

8

AI-07A-008

Lake Water Chemical Treatment Program

16

AP 23L-001

Lake Water Systems Corrosion and Fouling

Mitigation Program

2

SYS EF-300

ESW/Service Water Macrofoul Treatment

22

WCEM-06-005

Zebra Mussel Monitoring - 2008 Report and 2009

Plan

9

RNT 745679/0

Assessment of the Potential Impact of Zebra

Mussels on the Wolf Creek Power Plant and

Recommendations for Control

July 20, 2009

900030

Customer Assembly Neutron Flux Monitor System,

SNUPPS Generating Stations, Callaway 1 (Union

Elec Co) and Wolf Creek (Kansas Gas & Electric)

F

CCP 013096

Instrument Setpoints for RCP Thermal Barrier

Isolation and EGHV0062 Valves

1

A-16

Attachment 1

NUMBER

TITLE

REVISION /

DATE

EQDP-ESE-47A

Boron Dilution Fix: Source/Intermediate Range

Neutron Detector

0

M-762-00018-W03

Source and Intermediate Range Detector Assembly

August 19,

1988

NY-10042

Class 1E Qualified Proportional Counter and

Compensated Ionization Chamber Insulated

Assembly

September

1990

NY-10044

Qualified* Class 1E BF3 Proportional Counter

Assembly

September

1990

OE SE-09-008

Source Range Nuclear Instrument SEN0031

00

OE SE-09-011

Source Range Nuclear Instrument SEN0032

00

USAR 9.4.6

Containment HVAC

19

STS AE-205

Feedwater System Inservice Valve Test

November 120

09

LCO 3.0.4

Wolf Creek Technical Specifications

November 182

009

APF 22C-003-01

Operational Risk Assessment

November 172

009

n/a

Wolf Creek Operations Logs: Control Room Log

n/a

n/a

Wolf Creek Operations Logs: Equipment Out of

Service Log

n/a

n/a

Technical Specification LCO 3.0.4 Mode Change

Review Form - TDAFWP Inoperable

November 17,

2009

CONDITION REPORTS

NUMBER

TITLE

REVISION /

DATE

CR 19528

SOER 09-1: Shutdown Safety

September 1,

2009

CR 21286

ESW Self Cleaning Strainer Tubes Retain Debris

October 28,

2009

CR 19282

Source Range N31 Indication During Loss of Cavity

Cooling

August 20,

2009

A-17

Attachment 1

NUMBER

TITLE

REVISION /

DATE

CR 20208

Source Range Detector Operability Question

September 30,

2009

CR 20325

Effect on Cavity Components with Loss of Cavity

Cooling

October 6,

2009

CR 21906

T/S Log Entries Related to Entering Mode 3 with

TDAFWP OOS

November 19,

2009

CR 21926

Inconsistent Directions for Protected Train Signs in

Mode 3

November 19,

2009

CR 21286

ESW Self Cleaning Strainer Tubes Retain Debris

October 28,

2009

WORK ORDERS

NUMBER

TITLE

REVISION /

DATE

WO 09-322198-000

Create a RM/Repetitive Task to Open the ESW Self

Cleaning Strainers and Clean the Porous Strainer

Tubes

November 12,

2009

WO 09-319411-001

Source Range NI 31 Indication is Trending Up.

Evaluate Condition to Determine Cause

August 22,

2009

Section 1R15: Operability Evaluations

MISCELLANEOUS

NUMBER

TITLE

REVISION /

DATE

OE SE-09-008

Source Range Nuclear Instrument SEN0031

00

AI-07A-008

Lake Water Chemical Treatment Program

16

AP 23L-001

Lake Water Systems Corrosion and Fouling

Mitigation Program

2

AP 28-001

Operability Evaluations

17

AP 26C-004

Technical Specification Operability

January 13,

2010

SYS EF-300

ESW/Service Water Macrofoul Treatment

22

WCEM-06-005

Zebra Mussel Monitoring - 2008 Report and 2009

Plan

9

A-18

Attachment 1

NUMBER

TITLE

REVISION /

DATE

RNT 745679/0

Assessment of the Potential Impact of Zebra

Mussels on the Wolf Creek Power Plant and

Recommendations for Control

July 20,

2009

900030

Customer Assembly Neutron Flux Monitor System,

SNUPPS Generating Stations, Callaway 1 (Union

Elec Co) and Wolf Creek (Kansas Gas & Electric)

F

CCP 013096

Instrument Setpoints for RCP Thermal Barrier

Isolation and EGHV0062 Valves

1

EQDP-ESE-47A

Boron Dilution Fix: Source/Intermediate Range

Neutron Detector

0

M-762-00018-W03

Source and Intermediate Range Detector Assembly

August 19,

1988

NY-10042

Class 1E Qualified Proportional Counter and

Compensated Ionization Chamber Insulated

Assembly

September

1990

NY-10044

Qualified* Class 1E BF3 Proportional Counter

Assembly

September

1990

OE SE-09-008

Source Range Nuclear Instrument SEN0031

00

OE SE-09-011

Source Range Nuclear Instrument SEN0032

00

USAR 9.4.6

Containment HVAC

19

STS AE-205

Feedwater System Inservice Valve Test

November

9, 2009

n/a

Wolf Creek Operations Logs: Control Room Log

n/a

n/a

Wolf Creek Operations Logs: Equipment Out of

Service Log

n/a

LCO 3.0.4

Wolf Creek Technical Specifications

November

18, 2009

n/a

Technical Specification LCO 3.0.4 Mode Change

Review Form - TDAFWP Inoperable

November

17, 2009

APF 22C-003-01

Operational Risk Assessment

November

17, 2009

M-089-K027-06

Byron Jackson Report DC-1104

3

EF-S-043

Determine the Stress in the Essential Service Water

Pump (PEF01A) column housing using specified

maximum deflection

0

A-19

Attachment 1

CONDITION REPORTS

CR 19282

CR 20208

CR 20325

CR 21906

CR 22798

CR 21574

CR 21400

CR 21572

CR 21926

WORK ORDERS

NUMBER

TITLE

REVISION /

DATE

WO 09-319411-001

Source Range NI 31 Indication is Trending Up.

Evaluate Condition to Determine Cause

August 22,

2009

WO 09-322198-000

Section 1R18: Plant Modifications

NUMBER

TITLE

REVISION

AP 05-010

Design Drawings

6

AP 05D-001

Calculations

12

AP 05A-001

Design Inputs

1

AP 05-002

Dispositions and Change Packages

8

AP 05-005

Design, Implementation & Configuration of

Modifications

13

WCRE-01

Total Plant Setpoint Document

32

CCP 013096

Instrument Setpoints for RCP Thermal Barrier

Isolation and EGHV0062 Valves

01

AP 05-013

Review of Vendor Technical Documents

7A

NP 92-0996

Interoffice Correspondence from C. R. Morris, CCW

Low Transient (PMR 03580) Meeting

5/21/92

EG-M-016

Time Delay for Isolation of CCW High Flow to RCP

Thermal Barriers

1

M-738-0032-02

Functional Requirements and Design Criteria

Standard Single and Twin Units 212, 312, 412 Plants

Component Cooling System

3

CONDITION REPORT

CR 16243

A-20

Attachment 1

Section 1R19: Postmaintenance Testing

NUMBER

TITLE

REVISION

STN EF-201

ESW System Valve Test

2A

AP 16E-002

Post Maintenance Testing Development

8

AP 23D-001

Motor Operated Valve Program

2

STS IC-608A

Slave Relay Test K608A Train A Safety Injection

18

CONDITION REPORT

CR 19670

WORK ORDERS

06-291566-001

06-291566-012

09-316118-001

Section 1R20: Refueling and Other Outage Activities

NUMBER

TITLE

REVISION

WCRE-16

Inservice Inspection Program Plan Wolf Creek

Generating Station Interval 3

4

WCRE-23

Inservice Inspection Classification Basis Document

Wolf Creek Generating Station Interval 3

3/24/09

SYS BB-112

Vacuum Fill of the RCS

27

GEN 00-008

Reduced Inventory Operations

19

GEN 00-009

Refueling

23

GEN 00-003

Hot Standby to Minimum Load

73

SYS BB-215

RCS Drain Down with Fuel in Reactor

23A

STS RE-002

Determination of Estimated Critical Position

18

APF 19C-002-01

Wolf Creek Generating Station Fuel Transfer

Authorization

0

APF 22B-001-02

Daily Shutdown Risk Assessment

8

RWP 092602

Radiation Work Permit

1

RWP 092602

ALARA Review Package

7

RWP 091102

Radiation Work Permit

0

RWP 091102

ALARA Review Package

7

A-21

Attachment 1

NUMBER

TITLE

REVISION

RWP 091102

Radiation Work Permit

0

EID-0003

Refuel Level Indications

2

M-19BG24

Hanger Location DWG. Small Pipe CVCS Auxiliary

Spray Reactor Building

7

M-15BG21

Hanger Location DWG. Small Pipe CVCS - Normal

& Alternate Charging Reactor Building

12

M-12BG01

Piping & Instrumentation Diagram Chemical and

Volume Control System

14

M-12BB02

Piping & Instrumentation Diagram Reactor Coolant

System

16

n/a

Investigation into the Extent of Condition Related to

Linear Indications Discovered on Pressurizer

Auxiliary Spray Line at Wolf Creek Generating

Station

November 4,

2009

CONDITION REPORTS

CR 20528

CR 20628

CR 21366

CR 21387

CR 21719

CR 20622

CR 20893

WORK ORDERS

WO 09-321462-015

WO 08-303356-004

WO 09-321902-001

WO 08-303356-001

Section 1R22: Surveillance Testing

MISCELLANEOUS

NUMBER

TITLE

REVISION

STS AL-210A

MDAFW Pump A inservice check valve test

10

WCOP 02

Inservice Testing Program for Pumps and Valves

14

AP 29B-002

ASME code testing of pumps and valves

7

AP 29B-003

Surveillance Testing

10

AP 29B-001

IST Basis Document

3

A-22

Attachment 1

STS AL-212

MD AFP Comprehensive Pump Testing Flow Path

Verification & Check Valve Testing

14

AP 29A-004

ASME Section XI System Pressure Testing

7

QCP 20-520

Pressure Test Examination

8A

STS PE-007

Periodic Verification of Motor Operated Valves

3

AI 23D-002

MOV Calculation Guidelines

2

AI 23D-003

MOV Trending and Periodic Verification Program

1

AP 29E-001

Program Plan for Containment Leakage

Measurement

12

NEI 94-01

NEI Guideline for Implementing the Performance

Based Guideline of Appendix J

NEI 94-01

M-12AL01

Piping and Instrumentation Drawing Auxiliary

Feedwater

10

M-12AE01

Piping and Instrumentation Drawing Feedwater

37

M-12EF01

Piping and Instrumentation Drawing Essential

Service Water

21

M-12EF02

Piping and Instrumentation Drawing Essential

Service Water

25

M-724-00784

EJHV8811A/B Pressure Locking Bypass

W02

M-724-00696

Motor Operated Gate Valve

W06

M-12EJ01

Piping and Instrumentation Drawing Residual Heat

Removal System

43

CONDITION REPORTS

CR 1994-0881

CR 1998-0422

CR 2001-2237

CR 2005-1899

CR 2005-3545

CR 20723

CR 21308

CR 21343

WORK ORDERS

WO 05-278104-012

WO 09-321637-000

WO 09-321637-002

WO 09-321637-001

A-23

Attachment 1

Section 2OS1: Access Controls to Radiologically Significant Areas

CORRECTIVE ACTION DOCUMENTS

20878

15485

14874

19405

19409

21004

20973

20987

10196

9627

2008-1576

21029

20976

5633

PROCEDURES

NUMBER

TITLE

REVISION

AP 25A-700

Use of Temporary Shielding or Locked High Radiation Areas

and Very High Radiation Area Barricades

10

RPP 02-105

RWP

33

AP 22-01

Conduct of Pre-Job and Post-Job Briefs

9A

AP 25A-200

Access to Locked High or Very High Radiation Areas

20

SEC 01-206

High Security Key Control and Issue

32

AP 25B-200

Radiography Guidelines

12

RADIATION WORK PERMITS

93021

9220

92602

93230

Section 4OA2: Identification and Resolution of Problems

MISCELLANEOUS

NUMBER

TITLE

REVISION

SYS AF-200

High Pressure Heater Operations

8

AP 21-001

Conduct of Operations

43

AP 19E-002

Reactivity Management Program

13

CONDITION REPORTS

CR 18034

CR 04293

CR 2001-2255

A-24

Attachment 1

Section 40A5: Other Activities (TI-172 Dissimilar Metal Welds)

MISCELLANEOUS

NUMBER

TITLE

REVISION

UT-95

Ultrasonic Examination of Austenitic Piping Welds

3

WCRE-24

WESDYNE Year 2009 Reactor Vessel Nozzle Safe-

end Examinations Program Plan

0

WDI-CAL-102

Calibration Inspection Procedure for PCI Eddy

Current Card

1

WDI-EQPT-1021

Installation and Removal of the WESDYNE Nozzle

Scanner (SQUID)

4

WDI-EQPT-1022

Reactor Vessel Nozzle Scanner Setup and Checkout

2

WDI-STD-146

ET Examination of Reactor Vessel Pipe Welds Inside

Surface

9

A2-1

Attachment 2

Attachment 2

Significance Determination Process for Noncited Violation 2009005-16: Operator Actions

Disable Circuit Breaker Coordination and Could Initiate Secondary Fires

Introduction

This attachment discusses the risk significance of Noncited Violation 2009005-16. This

document discusses the methods, assumptions, and results of the significance determination

process.

Methods

The significance of this finding was evaluated using the significance determination process in

Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process,

because it affected fire protection defense-in-depth strategies involving post-fire safe shutdown

systems.

This finding was associated with the post-fire safe shutdown category. Specifically, the

performance deficiency resulted in loss of power to equipment assumed affected in the safe

shutdown analysis and could initiate secondary fires in plant locations outside of the initial fire

area. The inspectors assigned this finding a high degradation rating since the affected circuit

breakers would not provide any fire protection benefit and would receive no fire protection

credit.

The inspectors assigned a duration factor of 1.00 since the performance deficiency existed for

greater than 30 days. The inspectors performed a Phase 1 quantitative screening using generic

fire ignition frequencies for the 13 fire areas of concern. The results of this Phase 1 screening

concluded that a Phase 2 evaluation was needed.

The inspectors followed the guidance in Manual Chapter 0609, Appendix F, Fire Protection

Significance Determination Process, to perform the Phase 2 evaluation. In accordance with

Appendix F, the inspectors used several spreadsheets from NUREG-1805, Fire Dynamics

Tools (FDTs) Quantitative Fire Hazard Analysis Methods for the U.S. Nuclear Regulatory

Commission Fire Protection Inspection Program. The inspectors used the following

spreadsheets in the Phase 2 evaluation:

02.1_Temperature_NV

02.2_Temperature_FV

05.1_Heat_Flux_Calculations_Wind_Free

9_Plume_Temperature_Calculations

10_Detector_Activation_Times

The inspectors used these spreadsheets to determine the temperature of the plume, the

temperature of the hot gas layer, and the activation time of the detection systems.

A2-2

Attachment 2

Assumptions

The inspectors used the following assumptions during the Phase 2 evaluation:

1. The inspectors assumed that the smoke detectors were located at the maximum possible

distance from the ignition source given the spacing of detectors in each fire area.

2. The inspectors assumed that the detection systems worked properly to detect the fire.

3. The inspectors assumed that the fixed suppression systems would fail to suppress the fire.

The inspectors assumed the only method of suppressing the fire was manual fire fighting by

the fire brigade.

4. The inspectors assumed that operators would take the prescribed mitigating actions during

any fire scenario that progressed to the point where the power-operated relief valve

spuriously opened and its block valve failed to close. These mitigating actions include steps

for the operators to remove the 125 Vdc control power to the train affected by the fire.

5. The licensee concluded that an inter-cable hot short in thermoset cables was needed for a

power-operated relief valve to spuriously open. Using guidance in Appendix F, Table 2.8.3,

PSP Factors Dependent on Cable Type and Failure Mode, the inspectors assumed the

conditional probability of an inter-cable hot short given a fire scenario that damaged the

thermoset cables was 0.02.

6. The licensee performed an evaluation of the equipment affected by the loss of 125 Vdc

control power. The inspectors reviewed the evaluation and concluded that the loss of

125 Vdc control power did not directly affect the equipment relied upon for post-fire safe

shutdown in each of the fire areas.

7. Without any additional knowledge of the cable routing for the set of affected equipment, the

inspectors assumed that cables for the affected equipment were routed in the same cable

trays as cables for the power-operated relief valves or the associated block valves.

8. The inspectors assumed that any equipment that experienced a loss of dc control power

would experience a short to ground that would lead to a secondary fire in another plant

location.

9. The inspectors assumed that a secondary fire in another plant location would damage the

equipment relied upon for safe shutdown in the original fire area and would lead to core

damage. As such, the inspectors provided no credit for the designated post-fire safe

shutdown equipment.

10. The inspectors assumed that the change in core damage frequency associated with the

performance deficiency resulted from the increased likelihood of secondary fires because of

the loss of circuit breaker protection.

A2-3

Attachment 2

Evaluation

During the inspection, the licensee provided information for each of the 13 fire areas, with the

exception of the reactor building, which is not readily accessible during power operations. The

information provided included the location of the power-operated relief valve cables (targets); a

description and photographs of the nearest set of ignition sources near each target; and a

discussion of the room dimensions, ventilation, and fire protection features.

The inspectors performed a field walkdown to verify the information provided by the licensee. In

particular, the inspectors verified the spatial arrangement of the fire sources and targets as well

as the distances between each source and target. The inspectors used the zone of influence

described in Appendix F, step 2.3, Fire Scenario Identification and Ignition Source Screening,

to determine the fire sources that could lead to fire scenarios that damaged the power-operated

relief valves. These scenarios involved cases where the initial fire directly damaged the cables

as well as situations where the fire propagated through a set of cable trays that contained the

power-operated relief valve cables.

The inspectors reviewed the Wolf Creek Generating Station Individual Plant Examination of

External Events, the fire hazards analysis, and drawings showing the cable routing for the

power-operated relief valves and their associated block valves inside containment. The

inspectors screened out fire scenarios involving the reactor building given the lack of ignition

sources located under the power-operated relief valve cables.

The inspectors used the Fire Dynamics Tools to calculate the temperature of the hot gas layer

in each fire area. The inspectors concluded that the hot gas layer would never reach a high

enough temperature to damage the thermoset cables. Therefore, the inspectors screened out

all fire scenarios involving a hot gas layer that would damage the power-operated relief valve.

Based on the walkdown and hot gas layer evaluations, the inspectors created an initial set of

five fire sources involving nine fire scenarios that could lead to core damage. The scenarios are

listed in the following table. The categories assigned to components and values determined

related to the Source Category, Fire Ignition Frequency, Heat Release Rate, and Severity

Factor used to characterize the fire scenarios in the significance determination process are

described in Manual Chapter 0609, Appendix F. The inspectors summarized the fire scenarios

in Table 1, Initial Fire Scenarios.

Fire Scenarios

The detailed evaluation of each ignition source is provided below. In each of these scenarios,

the inspectors used the Fire Dynamics Tools to calculate the time to damage the

power-operated relief valve and block valve cables and the time to detect the fire. As noted

above, the inspectors assumed that the fixed suppression systems failed to suppress the fire

and the only method of suppression resulted from manual fire fighting from the fire brigade.

The inspectors used Manual Chapter 0609, Appendix F, Attachment 8, Table A8.1,

Non-Suppression Probability Values for Manual Fire Fighting Based on Fire Duration Time to

Damage after Detection) and Fire Type Category to calculate the non-suppression probability

for manual fire fighting. The results are different for each scenarios based on the type of fire

and the length of time between the detection of the fire and damage to the cables.

A2-4

Attachment 2

Table 2. Initial Fire Scenarios

Scenario

Number

Ignition

Source

Source

Description

(Fire Area)

Source

Category

Initial Fire

Ignition

Frequency

Heat

Release

Rate

Severity

Factor

Fire

Targets

Nearest

Distance

1

RP-333

Relay

Panel

(A-16)

General

Control

Cabinet

6.00E-5

200 kW

0.9

4U3B

4U3A

4.8 ft

2

RP-333

Relay

Panel

(A-16)

General

Control

Cabinet

6.00E-5

650 kW

0.1

4U3B

4U3A

4.8 ft

3

SK194B

Security

Panel

(A-16)

General

Electrical

Cabinet

6.00E-5

200 kW

0.1

4U3B

4U3A

5.0 ft

4

NG01B

600 V

MCC

(A-18)

General

Electrical

Cabinet

6.00E-5

70 kW

0.9

1U3J

1U3K

3.3 ft

5

NG01B

600 V

MCC

(A-18)

General

Electrical

Cabinet

6.00E-5

200 kW

0.1

1U3J

1U3K

3.3 ft

6

Transients

C-21

Transients

(Medium)

1.70E-4

70 kW

0.9

1C8H

1C8J

1.3 ft

7

Transients

C-21

Transients

(Medium)

1.70E-4

200 kW

0.1

1C8H

1C8J

1.3 ft

8

Transients

C-22

Transients

(Medium)

1.70E-4

70 kW

0.9

4C8E

4C8F

0.0 ft

9

Transients

C-22

Transients

(Medium)

1.70E-4

200 kW

0.1

4C8E

4C8F

0.0 ft

1. Source RP-333

Panel RP-333 is a relay panel located against a wall in Fire Area A-16. The top of the cabinet is

7 10 from the floor. The inspectors treated the relay panel as a general control cabinet with a

fire ignition frequency of 6.00E-5 and heat release rates of 200 kW and 650 kW.

The power-operated relief valve cables are located in cable tray 4U3B and the power-operated

relief valve block valve cables are located in cable tray 4U3A. Cable tray 4U3B is the third tray

and cable tray 4U3A is the fourth tray from the bottom of a stack of cable trays. The lowest

cable tray is located 11 8 from the floor.

Fire Area A-16 is protected by a single zone smoke detection system with a maximum distance

of 25 feet between detectors. Areas of cable tray concentration contain preaction sprinkler

systems for fixed fire suppression.

A2-5

Attachment 2

Scenario 1 - Heat Release Rate (200 kW)

The inspectors calculated a plume temperature of 1178°F, corresponding to a damage time of 1

minute for the lowest cable tray and a damage time of 10 minutes for the target set. The

inspectors calculated a detection time less than 1 minute. The inspectors assigned a

non-suppression probability for manual fire fighting of 0.35 for an electrical fire with 9 minutes

between the time to detection and time to damage.

Scenario 2 - Heat Release Rate (650 kW)

The inspectors calculated a plume temperature exceeding 2000°F, corresponding to a damage

time of 1 minute for the lowest cable tray and a damage time of 10 minutes for the target set.

The inspectors calculated a detection time less than 1 minute. The inspectors assigned a

non-suppression probability for manual fire fighting of 0.35 for an electrical fire with 9 minutes

between the time to detection and time to damage.

2. Source SK194B

Panel SK194B is a security panel located against a wall in Fire Area A-16. The top of the

cabinet is 7 8 from the floor. The inspectors treated the security panel as a general electrical

cabinet with a fire ignition frequency of 6.00E-5 and heat release rates of 70 kW and 200 kW.

Using a zone of influence, the inspectors screened out the lower heat release rate during the

plant walkdown.

The power-operated relief valve cables are located in cable tray 4U3B and the power-operated

relief valve block valve cables are located in cable tray 4U3A. Cable tray 4U3B is the third tray

and cable tray 4U3A is the fourth tray from the bottom of a stack of cable trays. The lowest

cable tray is located 11 8 from the floor.

Fire Area A-16 is protected by a single zone smoke detection system with a maximum distance

of 25 feet between detectors. Areas of cable tray concentration contain preaction sprinkler

systems for fixed fire suppression.

Scenario 3 - Heat Release Rate (200 kW)

The inspectors calculated a plume temperature of 1103°F, corresponding to a damage time of 1

minute for the lowest cable tray and a damage time of 10 minutes for the target set. The

inspectors calculated a detection time less than 1 minute. The inspectors assigned a

non-suppression probability for manual fire fighting of 0.35 for an electrical fire with 9 minutes

between the time to detection and time to damage.

3. Source NG01B

Panel NG01B is a 600V motor control center located in the open in Fire Area A-18. The top of

the cabinet is 7 8 from the floor. The inspectors treated the motor control center as a general

electrical cabinet with a fire ignition frequency of 6.00E-5 and heat release rates of 70 kW and

200 kW.

A2-6

Attachment 2

The power-operated relief valve cables are located in cable tray 1U3J and the power-operated

relief valve block valve cables are located in cable tray 1U3K. Cable tray 1U3J is the third tray

and cable tray 1U3K is the second tray from the bottom of a stack of cable trays. The lowest

cable tray is located 9 11 from the floor.

Fire Area A-18 is protected by a cross zone smoke detection system with a maximum distance

of 5 feet between detectors. A total flooding halon system provides fixed fire suppression.

Scenario 4 - Heat Release Rate (70 kW)

The inspectors calculated a plume temperature of 421°F. Since this is less than the damage

threshold of 625 °F for thermoset cables, the inspectors screened out this scenario from further

consideration.

Scenario 5 - Heat Release Rate (200 kW)

The inspectors calculated a plume temperature of 1019°F, corresponding to a damage time of 1

minute for the lowest cable tray and a damage time of 8 minutes for the target set. The

inspectors calculated a detection time less than 1 minute. The inspectors assigned a

non-suppression probability for manual fire fighting of 0.44 for an electrical fire with 7 minutes

between the time to detection and time to damage.

4. Transient Combustibles in Fire Area C-21 (Lower Cable Spreading Room)

Fire Area C-21 has a length of 88 and a width of 66. The area is protected by a single zone

smoke detection system with a maximum distance of 15 feet between detectors. A preaction

sprinkler system provides fixed fire suppression.

The power-operated relief valve cables are located in cable tray 1C8H and the power-operated

relief valve block valve cables are located in cable tray 1C8J. Cable tray 1C8H is the fifth tray

and cable tray 1U3K is the fourth tray from the bottom of a stack of cable trays. The lowest

cable tray is located 3 4 from the floor.

The inspectors determined that the cables for both valves were located in the same cable tray

stack for approximately 107 feet and the same cable tray for approximately 8 feet. For the

Phase 2 evaluation, the inspectors conservatively assumed that the cables for both valves were

located in the lower tray through the entire area. The inspectors assumed that the cables trays

were 2 feet wide.

For the following two scenarios, the inspectors adjusted the fire ignition frequency to account for

the limited areas where a fire could damage the targets. The inspectors modified the transient

combustible fire ignition frequency by multiplying the initial fire ignition frequency by a weighting

factor. The inspectors calculated the weighting factor by dividing the surface area of the cables

trays containing cables for both valves by the area of the fire area. The inspectors calculated a

modified fire ignition frequency for transient combustibles of 6.26E-6.

Scenario 6 - Heat Release Rate (70 kW)

The inspectors calculated a plume temperature of 943°F, corresponding to a damage time of 1

minute for the lowest cable tray and a damage time of 11 minutes for the target set. The

inspectors calculated a detection time less than 1 minute. The inspectors assigned a

A2-7

Attachment 2

non-suppression probability for manual fire fighting of 0.26 for transient fires with 10 minutes

between the time to detection and time to damage.

Scenario 7 - Heat Release Rate (200 kW)

The inspectors calculated a plume temperature exceeding 2000°F, corresponding to a damage

time of 1 minute for the lowest cable tray and a damage time of 11 minutes for the target set.

The inspectors calculated a detection time less than 1 minute. The inspectors assigned a

non-suppression probability for manual fire fighting of 0.26 for transient fires with 10 minutes

between the time to detection and time to damage.

5. Transient Combustibles in Fire Area C-22 (Upper Cable Spreading Room)

Fire Area C-22 has a length of 88 and a width of 67. The power-operated relief valve cables

are located in cable trays 4C8E, 4C8F, and 4C8G and the power-operated relief valve block

valve cables are located in cable trays 4C8F and 4C8G. These cable trays transition into the

control room through the floor of the upper cable spreading room.

The inspectors determined that cables for both valves were located in the same cable tray stack

for approximately 96 feet. For the Phase 2 evaluation, the inspectors conservatively assumed

that the cables for both valves were located in the same cable tray through the entire area and

that the cable tray was located on the floor. The inspectors assumed that the cables trays were

2 feet wide.

The inspectors did not credit the detection or suppression systems for the following two

scenarios since the fire was assumed to damage the target set immediately.

For the following two scenarios, the inspectors adjusted the fire ignition frequency to account for

the limited areas where a fire could damage the targets. The inspectors modified the transient

combustible fire ignition frequency by multiplying the initial fire ignition frequency by a weighting

factor. The inspectors calculated the weighting factor by dividing the surface area of the cables

trays containing cables for both valves by the area of the fire area. The inspectors calculated a

modified fire ignition frequency for transient combustibles of 5.54E-6.

Scenario 8 - Heat Release Rate (70 kW)

The inspectors postulated that the transient fire was located on the cable tray containing the

cables for both valves, corresponding to immediate damage for the target set. The inspectors

assigned a non-suppression probability for manual fire fighting of 1.00 for transient fires with no

time between detection and damage.

Scenario 9 - Heat Release Rate (200 kW)

The inspectors postulated that the transient fire was located on the cable tray containing the

cables for both valves, corresponding to immediate damage for the target set. The inspectors

assigned a non-suppression probability for manual fire fighting of 1.00 for transient fires with no

time between detection and damage.

A2-8

Attachment 2

Results

The inspectors used the Phase 2 evaluation to perform a bounding analysis and determine an

upper limit for the change in core damage frequency. In each of the scenarios described above,

the change in core damage frequency was bounded by the conditional core damage probability

(CCDP). The inspectors calculated the conditional core damage probability using the following

equation:

Short

Hot

n

Suppressio

Non

P

x

P

x

SF

x

FIF

CCDP

=

where:

FIF denotes the fire ignition frequency

SF denotes the severity factor

n

Suppressio

Non

P

denotes the non-suppression probability

Short

Hot

P

denotes the probability of a hot short

The sum of the conditional core damage probabilities for each of the fire scenarios bounded the

total change in core damage frequency associated with this performance deficiency. The

inspectors calculated a bounding value of 6.58E-7 for the change in core damage frequency for

this performance deficiency. The results from the nine scenarios described above are

contained in the following table:

A2-9

Attachment 2

Table 3. Phase 2 Evaluation Results

Scenario

Number

Ignition

Source

Fire Ignition

Frequency

Severity

Factor

Probability of

Non-Suppression

Probability of

a Hot Short

CCDP

1

RP-333

6.00E-5

0.9

0.35

0.02

3.78E-7

2

RP-333

6.00E-5

0.1

0.35

0.02

4.20E-8

3

SK194B

6.00E-5

0.1

0.35

0.02

4.20E-8

4

NG01B

6.00E-5

0.9

N/A

N/A

N/A

5

NG01B

6.00E-5

0.1

0.44

0.02

5.28E-8

6

Transient Fire

(C-21)

6.26E-6

0.9

0.26

0.02

2.93E-8

7

Transient Fire

(C-21)

6.26E-6

0.1

0.26

0.02

3.26E-9

8

Transient Fire

(C-22)

5.54E-6

0.9

1.00

0.02

9.96E-8

9

Transient Fire

(C-22)

5.54E-6

0.1

1.00

0.02

1.11E-8

Total

6.58E-7