Text

NRC-2020-000176 - Resp 1 - Final, Final, Final Agency Records Subject to the Request Are Enclosed. Part 3 of 3
	ML20073N010
Person / Time
Issue date:	03/02/2020
From:	; NRC/OCIO
To:	;
Shared Package
ML20073N003	List: ML20073N005; ML20073N006; ML20073N009; ML20073N010;
References
	FOIA, FOIA/PA-2013-00237, FOIA/PA-2013-00273, NRC-2020-000176
	Download: ML20073N010 (187)
	v • d • e

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AmyJ.Tillery atillery@hab-Iaw.com Civil Trial Lawyers June 4, 2013 VIA FIRST CLASS MAIL U.S. Nuclear Regulatory Commission Mail Stop T-5 F09 Washington, DC 20555-0001 Re:

Freedom of Information Act Request - Wolf Creek Generating Station 10 Burlington, Kansas Our File No.: 343-3

Dear NRC Representative:

This is a request for information under the Freedom of Information Act, which is codified at 5 U.S.C. 552.

We would like to receive copies of any documents concerning the NRC's investigation of the 73 day power outage that occurred at the Wolf Creek Generating Station beginning on or about January l3, 2012.

Please consider this request to include documents of any kind, whether hard copies, computerized, or in any way maintained. If the fees associated with this request are expected to exceed $250, please let me know in advance. Thank you for your time and attention to this matter. If you have any questions, please don't hesitate to call.

NRC FORM 464 Part I U.S. NUCLEAR REGULATORY COMMISSION FOIA/PA RESPONSE NUMBER (08-2013)

RESPONSE TO FREEDOM OF 2013- 0273 1

INFORMATION ACT (FOIA) / PRIVACY ACT(P)

RQUSTRESPONSE

['*FINAL

[*]PARTIAL ACT (PA) REQUEST TYPE REQUESTER DATE Amy Tillery AM 2 9 7IS PART I. -- INFORMATION RELEASED No additional agency records subject to the request have been located.

D Requested records are available through another public.distribution program. See Comments section.

W GROUP Agency records subject to the request that are identified in the specified group are already available for A

public inspection and copying at the NRC Public Document Room.

71 GROUP Agency records subject to the request that are contained in the specified group are being made available for B, C public inspection and copying at the NRC Public Document Room.

r* GROUPB, C Agency records subject to the request are enclosed.

ED Records subject to the request that contain information originated by or of interest to another Federal agency have been referred to that agency (see comments section) for a disclosure determination and direct response to you.

D We are continuing to process your request..

D See Comments.

PART L.A -- FEES AMOUNT*387.71 L

You will be billed by NRC for the amount listed.

L None. Minimum fee threshold not met.

See comments LZ' You will receive a refund for the amount listed.

F Fees waived.

for details Fed PART I.B -- INFORMATION NOT LOCATED OR WITHHELD FROM DISCLOSURE D

No agency records subject to the request have been located. For your information, Congress excluded three discrete categories of law enforcement and national security records from the requirements of the FOIA. See 5 U.S.C. § 552(c)

(2006 & Supp. IV (2010). This response is limited to those records that are subject to the requirements of the FOIA. This is a standard notification that is given to all our requesters and should not be taken as an indication that excluded records do, or do not, exist.

5 Certain information in the requested records is being withheld from disclosure pursuant to the exemptions described in and for the reasons stated in Part I1.

This determination may be appealed within 30 days by writing to the FOIA/PA Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. Clearly state on the envelope and in the letter that it is a "FOIA/PA Appeal."

PART I.C COMMENTS ( Use attached Comments continuation page if required)

The incoming FOIA Request can be located in ADAMS at ML 13179AO52.

Records with a ML Accession Number are publicly available in the NRC's Public Electronic Reading Room at http:www.nrc.gov/

reading-rm.html. If you need assistance in obtaining these records, please contact the NRC's Public Documents Room (PDR) at 301-415-4737, or 1-800-397-4209, or by e-mail to PDR.Resource@nrc.gov.

Requester will be refunded $387.71 (based on actual cost of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months search time [minus 2 free hours] @$56.36 per hour and $1.65 for the cost of I CD ROM). Requester previously paid $952.96 ( based on estimated costs)

SIGNATURE - FREEDOM OF Donna L. Sealing ti NRC FORM 464 Part 1 (08-2013)

NRC FORM 464 Part II U.S. NUCLEAR REGULATORY COMMISSION FOIA/PA (0 8 -2 0 1 3 )

e " - - -., 1%

2 0 1 3 -0 2 7 3

(! *,*

RESPONSE TO FREEDOM OF INFORMATION DATE ACT (FOIA) /PRIVACY ACT (PA) REQUEST I

2 ý, 2013 PART II.A -- APPLICABLE EXEMPTIONS GROUP Records subject to the request that are contained in the specified group are being withheld in their entirety or in part under the C, D Exemption No.(s) of the PA and/or the FOIA as indicated below (5 U.S.C. 552a and/or 5 U.S.C. 552(b)).

D-1 Exemption 1: The withheld information is properly classified pursuant to Executive Order 12958.

D Exemption 2: The withheld information relates solely to the internal personnel rules and practices of NRC.

D Exemption 3: The withheld information is specifically exempted from public disclosure by statute indicated.

D Sections 141-145 of the Atomic Energy Act, which prohibits the disclosure of Restricted Data or Formerly Restricted Data (42 U.S.C.

2161-2165).

D Section 147 of the Atomic Energy Act, which prohibits the disclosure of Unclassified Safeguards Information (42 U.S.C. 2167).

D*

41 U.S.C., Section 4702(b), prohibits the disclosure of contractor proposals in the possession and control of an executive agency to any person under section 552 of Title 5, U.S.C. (the FOIA), except when incorporated into the contract between the agency and the submitter of the proposal.

D Exemption 4: The withheld information is a trade secret or commercial or financial information that is being withheld for the reason(s) indicated.

D The information is considered to be confidential business (proprietary) information.

D The information is considered to be proprietary because it concerns a licensee's or applicant's physical protection or material control and accounting program for special nuclear material pursuant to 10 CFR 2.390(d)(1).

D The information was submitted by a foreign source and received in confidence pursuant to 10 CFR 2.390(d)(2).

D Disclosure will harm an identifiable private or governmental interest.

W Exemption 5: The withheld information consists of interagency or intraagency records that are not available through discovery during litigation.

Applicable privileges:

Deliberative process: Disclosure of predecisional information would tend to inhibit the open and frank exchange of ideas essential to the W

deliberative process. Where records are withheld in their entirety, the facts are inextricably intertwined with the predecisional information.

There also are no reasonably segregable factual portions because the release of the facts would permit an indirect inquiry into the predecisional process of the agency.

D Attorney work-product privilege. (Documents prepared by an attorney in contemplation of litigation)

ED Attorney-client privilege. (Confidential communications between an attorney and his/her client) r Exemption 6: The withheld information is exempted from public disclosure because its disclosure would result in a clearly unwarranted invasion of personal privacy.

D Exemption 7: The withheld information consists of records compiled for law enforcement purposes and is being withheld for the reason(s) indicated.

(A) Disclosure could reasonably be expected to interfere with an enforcement proceeding (e.g., it would reveal the scope, direction, and focus of enforcement efforts, and thus could possibly allow recipients to take action to shield potential wrong doing or a violation of NRC requirements from investigators).

D (C) Disclosure could constitute an unwarranted invasion of personal privacy.

D (D)

The information consists of names of individuals and other information the disclosure of which could reasonably be expected to reveal identities of confidential sources.

F]

(E) Disclosure would reveal techniques and procedures for law enforcement investigations or prosecutions, or guidelines that could reasonably be expected to risk circumvention of the law.

D (F) Disclosure, could reasonably be expected to endanger the life or physical safety of an individual.

1 OTHER (Specify)

Outside of Scope PART II.B -- DENYING OFFICIALS Pursuant to 10 CFR 9.25(g), 9.25(h), and/or 9.65(b) of the U.S. Nuclear Regulatory Commission regulations, it has been determined that the information withheld is exempt from production or disclosure, and that its production or disclosure is contrary to the public interest. The person responsible for the denial are those officials identified below as denying officials and the FOIA/PA Officer for any denials that may be appealed to the Executive Director for Operations (EDO).

DENYING OFFICIAL TITLE/OFFICE RECORDS DENIED EDO I

SECY IcIG Eric J. Leeds Director, Office of Nuclear Reactor Regulation Appendix C z

D]

[D Dr. Brian W. Sheron Director, Office of Nuclear Regulatory Research Appendix D D

[

]E.DD Appeal must be made in writing within 30 days of receipt of this response. Appeals should be mailed to the FOIA/Privacy Act Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, for action by the appropriate appellate official(s). You should clearly state on the envelope and letter that it is a "FOIA/PA Appeal."

NRC FORM 464 Part 11 (08-2013)

FOIA/PA-2013-0273 APPENDIX A RECORDS ALREADY PUBLICLY AVAILABLE NO.

DATE

1.

04/04/12

2.

03/15/13

3.

08/16/12

4.

03/15/13

5.

07/12/13

6.

05/16/13

7.

05/16/13 ACCESSION NUMBER ML12095A414 ML13073A172 ML122260214 ML13073A205 ML13109A234 ML13115A184 ML13115A190 DESCRIPTION/ (PAGE COUNT)

Letter from E. Collins, NRC to M. Sunseri, Wolf Creek Generating Station on IR 05000482-12-008, on 01/30/12 - 03/06/12, Wolf Creek Nuclear Operating Corporation -

NRC Augmented Inspection Team Report.

(58 pages)

Letter from F. Lyon, NRR to M. Sunseri, Wolf Creek Generating Station on Preliminary Accident Sequence Precursor Analysis of January 2012 Loss of Offsite Power Event (2 pages)

Memorandum from J. McHale, NRR to H.

Chernoff, NRR on IOLB Evaluation of IFR 2012-04 Relating to Wolf Creek Loss of Offsite Power and Notification of Unusual Event. (6 pages)

Wolf Creek Generating Station - Enclosure -

Preliminary Accident Sequence Precursor Analysis of January 2012Loss of Offsite Power Event. (24 pages)

Memo from R. Mathew, NRR to H. Chernoff, NRR on Safety Evaluation Regarding Wolf Creek Generating Station - loss of offsite power and Augmented Inspection, Issue for resolution 2012-004. (12 pages)

Transmittal Memo of Final Wolf Creek Generating Station Accident Sequence Precursor Analysis (3 pages)

Final ASP Analysis-Wolf Creek Generating Station, Multiple Switchyard Faults Cause Reactor Trip and Subsequent Loss of Offsite Power (24 pages)

FOIA/PA-2013-0273 APPENDIX B RECORDS BEING RELEASED IN THEIR ENTIRETY NO.

DATE

1.

Undated

2.

01/20/12

3.

01/23/12

4.

01/25/12

5.

01/25/12

6.

01/25/12

7.

01/31/12

8.

01/31/12

9.

02/22/12

10.

06/19/13

11.

08/21/12

12.

10/23/12 DESCRIPTION/ (PAGE COUNT)

Photographs of pictures of cables from Wolf Creek. (4 pages)

Email from M. King, NRR to J. Robles, NRR and R. Hall, NRR FW: Wolf Creek Status - regarding reactive inspection. (1 page)

Email from R. Sigmon, NRR to J. Thompson, NRR RE: MD 8.3 decision to conduct AIT at Wolf Creek. (1 page)

Email from M. King, NRR to H. Chernoff, NRR et al., FW: Wolf Creek AIT is requesting an IOEB team member to be assigned to support the AIT. (1 page)

Email from R. Hall, NRR to J. Andersen, NRR et al., FW: Draft Wolf Creek AIT Charter. (1 page)

Email from M. King, NRR to R. Hall, NRR and J. Robles, NRR RE:

Draft Wolf Creek AIT Charter - does NRR need to concur on the Charter? (3 pages)

Email from S. Pannier, NRR to J. Robles, NRR RE: Wolf Creek AIT. (1 page)

Email from R. Telson, NRR to J. Robles, NRR RE: Wolf Creek AIT. (1 page)

Email from K. Gray, NRR to J. Robles, NRR FW: Matharu, Gurcharan has completed the Green From for TAC ME8O.04.

(1 page)

OpE Communication on Augmented Inspection - Wolf Creek Generating Station Loss of Offsite Power and Notification of Unusual Event. (5 pages)

Email from J. Robles, NRR to J. Robles, NRR et al. RE: IFR 2012-04 - Wolf Creek LOOP/NOUE and Augmented Inspection Team Review. (1 pages)

Email from J. Andersen, NR to P. Sahay, NRR FW: Wolf Creek IFR 2012 TAC ME8004. (1 page)

FOIAIPA-2013-0273 APPENDIX C RECORDS BEING WITHHELD IN PART DESCRIPTION/ (PAGE COUNT)IEXEMPTIONS NO.

DATE

1.

01/17/12

2.

01/23/12

3.

01/23/12

4.

01/31/12

5.

02/16/12

6.

03/22/12

7.

05/08/12 Email from M. King, NRR on IOEB Clearinghouse Screening Summary for Tuesday, January 17, 2012. (3 pages) Outside of Scope Email from J. Thompson, NRR to M. King, NRR and R. Hall, NRR on RE: MD 8.3 for Call Participants - Wolf Creek call - should be at 3 PM today EDT per Randy Hall, PM - they are recommending an AIT. (2 pages) Exemption 6 Email from M. King, NRR on lOEB Clearinghouse Screening Summary for Monday, January 23, 2012. (4 pages) Outside of Scope Email from M. King, NRR on IOEB Clearinghouse Screening Summary for Tuesday, January 31, 2012. (4 pages) Outside of Scope Email from M. King, NRR on IOEB Clearinghouse Screening Summary for Thursday, February 16, 2012. (5 pages) Outside of Scope Email from M. King, NRR to J. Robles, NRR FW: Reqeust for a Technical Contact. (2 pages) Outside of Scope and Exemption 6

Email from M. King, NRR on lOEB Clearinghouse Screening Summary for Tuesday, May 8, 2012. (2 pages) Outside of Scope Email from G. Matharu, NRR to P. Sahay, NRR FW: Wolf Creek IFR 2012 TAC ME8004. (3 pages) Outside of Scope Email from M. King, NRR to R. Kendzia, NRO and J. Robles, NRR FW: Wolf Creek event followup on EN 47590 - from lOEB Clearinghouse Screening Summary for Tuesday, January 17, 2012. (2 pages) Exemption 6

8.

10/24/12

9.

01/19/12

Re: FOIAIPA-2013-0273 APPENDIX D RECORDS BEING WITHHELD IN THEIR ENTIRETY NO.

DATE

1.

02/22/13 DESCRIPTIONI(PAGE COUNT)/EXEMPTIONS Memorandum from Doug H. Coe, Acting Director, Division of Risk Analysis, Office of Nuclear Regulatory Research to Michele G. Evans, Division of operating Reactor Licensing, Office of Nuclear Reactor Regulation,

Subject:

Transmittal of Preliminary Wolf Creek Generating Station Accident Sequence Precursor Analysis For Internal and Licensee Review(3 pages) / Exemption 5

April 4, 2012 Matthew W. Sunseri, President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation P.O. Box 411 Burlington, KS 66839

SUBJECT:

WOLF CREEK NUCLEAR OPERATING CORPORATION - NRC AUGMENTED INSPECTION TEAM REPORT 05000482/2012008

Dear Mr. Sunseri:

On March 6, 2012, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Wolf Creek Generating Station. The enclosed report documents the inspection results, which were discussed with you and other members of your staff during a public exit meeting on March 6, 2012.

On January 13, 2012, Wolf Creek Generating Station declared a Notification of Unusual Event (NOUE) at 2:15 p.m. following an automatic reactor trip and loss of offsite power. The loss of offsite power was the result of two separate electrical failures: the failure of a main generator output breaker, followed by an unexpected loss of power to the startup transformer, which together caused the switchyard to be deenergized. All safety systems initially responded as expected, and emergency diesel generators automatically powered safety-related equipment.

Wolf Creek terminated the NOUE after offsite power was restored to safety-related buses approximately 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months into the event, and the plant was cooled down. The licensee restored power to most of the plant systems on January 17 after verifying that the non-vital switchboards were safe to energize. There were no radiological releases due to this event.

In accordance with Management Directive 8.3, NRC Incident Investigation Program, deterministic and conditional risk criteria were used to evaluate the level of NRC response for this operational event. Because two deterministic criteria were met (multiple failures in systems used to mitigate the event, and repetitive failures or events involving safety-related systems),

and the conditional core damage probability for the event was estimated to be in the overlap range for a special inspection/augmented inspection, Region IV concluded that the NRC response should be an augmented inspection team.

Based on inspection, the team concluded that: (1) your operators responded to the event in a manner that protected public health and safety; (2) safety system functions were maintained; and (3) equipment issues, some of which you had knowledge of but hadnt corrected before this event, complicated the response to this event. The purpose of this inspection was to gather facts and identify issues requiring follow-up, and, as such, no findings were identified. Items requiring additional follow-up are documented as unresolved items in the enclosed report. NRC UNITED STATES NUCLEAR REGULATORY COMMISSION REGION IV 1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511

inspectors have verified that those equipment issues required to be resolved before plant startup were adequately resolved.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the 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/

Elmo E. Collins Regional Administrator Docket No.: 05000482 License No: NPF-42

Enclosure:

Inspection Report 05000482/2012008 w/ Attachments:

1. Supplemental Information

2. Sequence of Events

3. Augmented Inspection Team Charter cc w/ encl: Electronic Distribution

DISTRIBUTION:

Regional Administrator (Elmo.Collins@nrc.gov)

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

DRP Director (Kriss.Kennedy@nrc.gov)

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

DRS Director (Anton.Vegel@nrc.gov)

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

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

Resident Inspector (Charles.Peabody@nrc.gov)

WC Administrative Assistant (Shirley.Allen@nrc.gov)

Branch Chief, DRS/OB (Mark.Haire@nrc.gov)

Branch Chief, DRP/B (Neil.OKeefe@nrc.gov)

Senior Project Engineer, DRP/B (Leonard.Willoughby@nrc.gov)

Project Engineer, DRP/B (Nestor.Makris@nrc.gov)

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

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

Project Manager (Randy.Hall@nrc.gov)

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

RITS Coordinator (Marisa.Herrera@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

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

OEMail Resource RIV/ETA: OEDO (Lydia.Chang@nrc.gov)

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

RSLO (Bill.Maier@nrc.gov)

D/DIR, DORL (Louise.Lund@nrc.gov)

PM (Randy.Hall@nrc.gov)

D: NRR (Eric.Leeds@nrc.gov)

D: NSIR (Jim.Wiggins@nrc.gov)

NRR/LPL4 (Michael.Markley@nrc.gov)

NRR/IOEB (Harold.Chernoff@nrc.gov)

EDO (Bill.Borchardt@nrc.gov)

DEDR (Martin.Virgilio@nrc.gov)

NRR_Reactive_Inspection Resource (NRR_Reactive_Inspection@nrc.gov)

File located: S:\\DRP\\DRPDIR\\_WC SUNSI Rev Compl.

Yes No ADAMS Yes No Reviewer Initials MSH Publicly Avail.

Yes No Sensitive Yes No Sens. Type Initials MSH AIT Member AIT Member AIT Member AIT Member AIT Leader C:DRP/B BCorrell JDixon JWatkins MRunyan MHaire NOKeefe

/RA/

03/23/2012 03/26/2012 03/22/2012 03/22/2012 03/28/2012 03/30/12 D:DRP RA KKennedy ECollins

/RA/

04/02/12 04/04/12 OFFICIAL RECORD COPY

Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket:

05000482 License:

NPF-42 Report:

05000482/2012008 Licensee:

Wolf Creek Nuclear Operating Corporation Facility:

Wolf Creek Generating Station Location:

1550 Oxen Lane NE Burlington, Kansas Dates:

January 30 through March 6, 2012 Team Leader:

Mark Haire, Operations Branch Chief Inspectors:

Mike Runyan, RIV Senior Reactor Analyst John Dixon, RIV Senior Resident Inspector at South Texas Project Brian Correll, RIV Reactor Inspector John Watkins, RIV Reactor Inspector Gurcharan Matharu, NRR Senior Electrical Engineer Jesse Robles, NRR Reactor Systems Engineer Approved By:

Neil OKeefe, Chief, Projects Branch B

Enclosure TABLE OF CONTENTS

SUMMARY

OF FINDINGS......................................................................................................... 3 EXECUTIVE

SUMMARY

........................................................................................................... 5 1.0 Description of Event (Charter Item #1)............................................................................ 6 1.1 Summary Sequence........................................................................................... 6 1.2 Probable Cause.................................................................................................. 9 2.0 Evaluate Licensee Actions (Charter Item #2).................................................................10 3.0 Assess Procedures (Charter Item #3)............................................................................11 4.0 Plant Response (Charter Item #4).................................................................................12 5.0 Turbine-Driven Auxiliary Feedwater Pump (Charter Item #5).........................................13 6.0 Emergency Diesel Generator B Ground (Charter Item #6).............................................15 7.0 Essential Service Water System Water Hammer and Leak (Charter Item #7)................17 8.0 Source Range Nuclear Instrument Deviation (Charter Item #8).....................................20 9.0 Temporary Fire Pump (Charter Item #9)........................................................................21 10.0 Past Maintenance Impact (Charter Item #10)................................................................24 11.0 Impacts of Prolonged Loss of Offsite Power (Charter Item #11)....................................26 12.0 Independent Risk Assessment (Charter Item #12)........................................................28 13.0 Assess Quality Assurance (QA), Radiological, Security, and Safety Conscious Work Environment (SCWE) Aspects (Charter Item #13).........................................................30 14.0 Exit Meeting Summary..................................................................................................30 ATTACHMENT 1: SUPPLEMENTAL INFORMATION........................................................... A1-1 ATTACHMENT 2: SEQUENCE OF EVENTS........................................................................ A2-1 ATTACHMENT 3: AUGMENTED INSPECTION TEAM CHARTER....................................... A3-1

Enclosure

SUMMARY

OF FINDINGS IR 05000482/2012008, 01/30/2012 through 03/06/2012, Wolf Creek Generating Station; Augmented Inspection Team.

An Augmented Inspection Team (AIT) was dispatched to the site on January 30, 2012, to assess the facts and circumstances surrounding a loss of offsite power that occurred on January 13, 2012. The AIT was established in accordance with NRC Management Directive 8.3, NRC Incident Investigation Program, and implemented using Inspection Procedure 93800, Augmented Inspection Team. The inspection was conducted by a team of inspectors from the NRCs Region IV office and the senior resident inspector from the South Texas Project with remote assistance from one reactor systems engineer and one senior electrical engineer from the NRC Office of Nuclear Reactor Regulation (NRR). The team identified 13 issues that will require additional NRC inspection. These issues are tracked as unresolved items in this report.

On January 30, 2012, an Augmented Inspection Team (AIT) was dispatched to Wolf Creek Generating Station to gather facts and understand the circumstances surrounding the January 13, 2012, loss of offsite power (LOOP). The LOOP was the result of two equipment failures: a) a fault on the main generator output breaker, and b) a differential relay trip of the startup transformer. The LOOP lasted almost 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months before offsite power was partially restored, although it took 4 days to restore power to most non-safety equipment. All safety systems performed their functions to support a safe shutdown and cooldown of the plant. However, there were five additional equipment malfunctions that complicated the event response:

o The turbine-driven auxiliary feedwater (AFW) pump experienced an inadvertent overspeed trip mechanism actuation while the operators were shutting down the pump.

o The B emergency diesel generator developed a ground on the field circuit but continued to function normally.

o The essential service water system experienced a water hammer event and a 5 gpm leak inside containment.

o One source range nuclear instrument gave inaccurate readings.

o Operators experienced considerable difficulty and delays in getting the temporary diesel fire pump in service, so normal fire fighting water was not available for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months .

The team concluded that operators responded appropriately to the event, and safety system functions were maintained; however, equipment issues, some of which were known problems that had not been corrected before the event, complicated the response to this event. The AIT identified 13 unresolved items requiring follow-up inspection to determine the existence and significance of any associated performance deficiencies.

A. NRC-Identified and Self-Revealing Findings No findings were identified.

Enclosure B. Licensee-Identified Violations None.

Enclosure EXECUTIVE

SUMMARY

On January 30, 2012, an Augmented Inspection Team (AIT) was dispatched to Wolf Creek Generating Station to gather facts and understand the circumstances surrounding the January 13, 2012, loss of offsite power (LOOP). The LOOP was the result of two equipment failures: a) a fault on the main generator output breaker, and b) a differential relay trip of the startup transformer. The LOOP lasted almost 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months before offsite power was partially restored. All safety systems performed their functions to support a safe shutdown and cooldown of the plant. However, there were five additional equipment malfunctions that complicated the event response:

1) The turbine-driven auxiliary feedwater (AFW) pump experienced an inadvertent overspeed trip mechanism actuation while the operators were shutting down the pump.

2) The B emergency diesel generator developed a ground on the field circuit but continued to function normally.

3) The essential service water system experienced a water hammer event and a 5 gpm leak inside containment.

4) One source range nuclear instrument gave inaccurate readings.

5) Operators experienced considerable difficulty and delays getting the temporary diesel fire pump in service because of equipment, training, and procedural problems.

The AIT identified 13 unresolved items requiring follow-up inspection to determine the existence and significance of any associated performance deficiencies:

1) Assess the cause determination for the main generator output breaker fault.

2) Assess the cause determination for the startup transformer fault.

3) Assess the maintenance deficiency associated with setting dimensions in the turbine mechanical trip linkage mechanism for the turbine-driven AFW pump.

4) Assess operating the turbine-driven AFW pump contrary to vendor recommendations.

5) Assess whether the B emergency diesel generator field ground would have impacted the ability of the generator to perform reliably through its design mission time.

6) Assess the adequacy and timeliness of licensee corrective actions to mitigate a long-standing history of water hammer events in the essential service water system.

7) Assess the adequacy of pipe wall-thickness examinations performed to assure the operability of the essential service water system.

8) Assess the adequacy and timeliness of corrective actions associated with source range nuclear instrument indication problems.

9) Assess the failure to maintain the fire system available for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months .

10) Assess the adequacy of the installation and operating procedures of the temporary diesel-driven fire pump.

11) Assess the adequacy of the temporary fire pump design.

12) Assess whether the September 13, 2011, failure of the normal diesel fire pump was maintenance-related.

13) Assess the design of the power supply for some protected area perimeter assessment equipment.

Enclosure 1.0 Description of Event (Charter Item #1) 1.1 Summary of the Sequence of Events Prior to the event, Wolf Creek Generation Station was operating at 100 percent power with no plant evolutions in progress, no transmission switching events occurring, and no severe weather conditions. All plant systems were lined up and performing as designed except reactor coolant system pressurizer power operated relief valve (PORV) PCV-455A, which was isolated by closing its block valve because of valve seat leakage.

Figure-1 shows a simplified schematic of the Wolf Creek electrical distribution system.

This figure, along with the Sequence of Events in Attachment 2 and systems descriptions below, will aid in understanding of the event.

Figure-1, Wolf Creek Simplified Electrical Distribution On January 13, 2012, at 2:02 p.m. CST, the site experienced a loss of offsite power (LOOP). The event resulted from two distinct faults. The first fault was on the C phase

Enclosure of main generator output breaker 345-60. This fault resulted in the 345 kVac east bus differential relay protective logic to open breakers 345-120, 345-90, 345-60, 13-48, and 69-16, which together deenergized the east bus. As a result of the location of the fault on the C phase of the 345-60 breaker, the main generator differential relay protective logic opened breaker 345-50. This resulted in a main generator trip signal, and started the sequence of events to shift the source of power to most station loads from the unit auxiliary transformer to the startup transformer in a sequence called a fast bus transfer.

The fast bus transfer resulted in breakers PA0211 and PA0101 opening, and breakers PA0202 and PA0110 closing. This completed the fast bus transfer and now had the station loads aligned through the startup transformer. The second fault, a phase differential, occurred on the B phase of the startup transformer and resulted in the 345 kVac west bus differential relay protective logic opening breakers 345-40, 345-70, and 345-110, deenergizing the remaining portions of the switchyard. It also resulted in the startup transformer phase differential relay protective logic opening breakers PA0110, PA0201, and PA0202. The sequence of events to this point all occurred in approximately 12 cycles (about 0.2 seconds) resulting in Wolf Creek experiencing a LOOP condition. The A and B emergency diesel generators automatically started and were powering the safety buses approximately 8 seconds after the start of the event. At 2:15 p.m., the shift manager declared a Notification of Unusual Event based on the expectation that the LOOP would last longer than 15 minutes. At 4:45 p.m., the 345 kVac east bus was reenergized from La Cygne by closing breaker 345-120, restoring offsite power to train A safety-related components. At 5:09 p.m., the Notification of Unusual Event was terminated.

The licensee safely cooled down the reactor coolant system; however, they encountered a number of challenges during the event.

As a result of a previous failure, the normal diesel-driven fire pump was not available and a temporary diesel-driven fire pump was used in its place. The temporary diesel-driven fire pump did not have an automatic start feature, and was drained to prevent freezing. Operators had difficulty in priming it; consequently, the station was initially without a working fire water supply for approximately 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months . Over the next couple of days, the licensee struggled to keep the temporary diesel-driven fire pump operating and lost all fire water pressure multiple times. Additionally, the licensee did not promptly implement compensatory measures for the loss-of-fire water.

The loss of power resulted in the loss of instrument air pressure, which resulted in the reactor coolant letdown system isolating and the reactor coolant charging system flow increasing to maximum. This combination of events (expected for the plant conditions) increased reactor coolant system pressure (due to compressing the steam bubble in the pressurizer) and resulted in the reactor coolant system pressurizer power-operated relief valve (PORV) PCV-456A cycling open and closed 23 times until the instrument air compressors could be restarted and letdown restored.

Enclosure Two hours and 43 minutes into the event, a senior reactor operator reviewing post trip review trends identified a possible water leak inside containment. It was later determined that the water leak was about 5 gpm from the essential service water system piping at the C reactor containment air cooler.

The count rate on source range nuclear instrument NI-31 began to increase when post-trip reactor power was decreasing as expected on NI-32 (this occurred with all rods inserted and the reactor shutdown). The licensee had previous experience that showed that, as reactor cavity temperature increased upon a loss of reactor cavity cooling (in this case as a result of the LOOP), the count rate on NI-31 would increase. This resulted in having only one reliable source range nuclear instrument remaining operable until reactor cavity temperatures decreased during the plant cooldown, which took about 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months .

However, the licensee can monitor and credit the Gamma Metrics detectors in addition to the source range nuclear instruments and was able to comply with technical specifications under these conditions.

Temporary modifications were performed to restore power to chemistry and health physics equipment to support reactor coolant chemistry sampling.

Additional temporary modifications were performed to power other nonvital loads, such as auxiliary building sump pumps. These modifications were not required to safely shutdown the plant.

The licensee performed an emergency hydrogen purge of the main generator to prevent dangerous hydrogen leakage because the battery powering the seal oil pumps was being depleted; and later they had a tractor trailer of CO2 delivered to purge the hydrogen from the main generator, since the installed CO2 system had not been functional since 2008. Calling for the CO2 delivery was proceduralized.

The turbine-driven auxiliary feedwater pump (AFW) pump experienced an inadvertent actuation of the overspeed trip mechanism while the operators were shutting it down after it had operated continuously for 12.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months .

The B emergency diesel generator developed a generator field ground alarm; the generator had been operating for 22.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months when the alarm came in and continued to operate normally for another 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months until it was no longer needed.

The reactor coolant system was cooled down using natural circulation until residual heat removal could be placed in service; the plant was safely stabilized in cold shutdown conditions at 7:50 a.m. on January 14. The licensee restored power to most of the plant systems on January 17, by back-feeding through the main and auxiliary transformers after performing extensive inspections to verify that the nonvital switchboards were safe to energize. There were no radiological releases due to this event.

A more detailed sequence of events can be found in Attachment 2.

Enclosure 1.2 Probable Cause

a.

Inspection Scope The team conducted an independent review of the licensees actions taken to understand the probable cause of the LOOP. This included reviewing the licensees determination that two distinct events occurred; the first on the C phase of the main generator output breaker 345-60 and the second on the B phase of the startup transformer.

The team reviewed the safety analysis, technical specifications, vendor manuals, design basis documents, system health reports, the post-trip report, the failure mode report for the main generator breaker, control room logs, operator statements, troubleshooting plans, and interviewed personnel. The review included understanding the licensees criteria for determining the root cause, or if one could not be determined, the most probable cause. Specific documents reviewed are listed in Attachment 1.

b.

Observations The team identified two unresolved items (URIs) requiring follow-up inspection. One URI involved reviewing the root cause analysis of the main generator output breaker fault when it is completed, and the second URI involved reviewing the root cause analysis of the startup transformer fault when it is completed.

At the time that the team left the site, the licensee had not determined the root cause of the main generator output breaker 345-60 fault. It was unclear if the root cause could be determined based on the damage that was identified internal to the breaker. Therefore, the inspectors focused on the licensees determination of the most probable cause and the method that the licensee used to reach that conclusion. The licensee and Westar (the company that operates the switchyard at Wolf Creek) representatives cooperated with the breaker manufacturer, HVB, to conduct a failure analysis at the HVB plant. In addition, Westar contracted the National Electric Energy Testing Research and Applications Center to provide an independent failure analysis. Based on the resulting failure analysis, the licensee made a preliminary determination that the failure of the 345-60 breaker was most likely due to internal particulate contamination introduced during manufacturing, but they were still waiting for an independent review of the failure mode data and for isotopic analysis of residue from inside the breaker to finalize that conclusion. The NRC will review the final cause assessment for the 345-60 breaker fault, which will be tracked as URI 05000482/2012008-01, Review Main Generator Output Breaker Fault Cause.

When the team left the station, the licensee was still performing troubleshooting activities on the startup transformer to determine the cause of the B phase fault. The licensee tested current transformer (CT) ratios, polarity, and saturation and CT megger tests of the high voltage section were performed on each individual CT. No anomalies were found and troubleshooting and evaluation did not reveal any damage or cause for the fault. The licensee contracted TransGrid Solutions to develop a computer model to

Enclosure further analyze the fault and test failure mode theories related to inrush current and harmonics. The licensee put the startup transformer back into service on February 3, 2012, after concluding that it was safe to restore in order to support further testing.

On February 13, 2012, the licensee experienced another fault on the B phase of the startup transformer while attempting to start the A reactor coolant pump. Testing equipment had been installed to monitor the performance of the transformer, and data obtained during the February 13 fault was reviewed. The licensee reevaluated the previous troubleshooting plan to determine additional testing that needed to be performed to determine the cause of the B phase fault. Subsequent troubleshooting identified a short between two unused taps of the high side CTs caused by missing insulation sleeves on wires in the transformer that likely caused the false actuation of the transformers protective relay both times. These wires were associated with providing electrical current indication to the differential current trip circuit. The licensee corrected this condition by restoring the insulation and tested the restored connections by starting all reactor coolant pumps successfully. The NRC will review the final cause assessment for the 345-60 breaker fault, which will be tracked as URI 05000482/2012008-02, Review Startup Transformer Fault Cause.

2.0 Evaluate Licensee Actions (Charter Item #2)

a.

Inspection Scope The team conducted an independent review of licensee actions taken in response to the event to determine if licensee staff responded properly during the event. The following areas were specifically addressed:

Assess licensee actions taken in response to the event. This activity focused on immediate control room staff actions to stabilize the plant in hot standby using Emergency Operating Procedures (EOPs).

Assess control room staffs actions to cool the plant down to cold shutdown.

Assess other operator actions.

Assess event classification and reporting.

The inspectors conducted interviews with on-shift personnel and reviewed the post-trip report, which included control room logs, operator statements, and plant data trends to assess overall performance of the crew. With respect to operator awareness and decision-making, the team focused on the effectiveness of control board monitoring, training for EOP implementation, technical decision-making, and the work practices of the operating crew. With respect to command and control, the team focused on actions taken by the control room supervision in managing the operating crews response to the event.

b.

Observations

Enclosure The team concluded that EOPs were implemented in a manner that was consistent with training. The team determined that operators exhibited fundamental operator competencies when responding to the event while using EOPs. Specifically, the team determined that the operating crew promptly identified the reactor trip and LOOP, and identified important off-normal parameters and alarms in a timely manner. The crew appropriately identified and addressed abnormal equipment alignments associated with non-safety-related equipment that could challenge personnel safety. Additionally, the team determined that operating crew supervision exercised adequate oversight of plant status, crew performance, and site resources.

The team reviewed the post-trip report performed by the licensee in which the licensee identified that a small steam void may have been present in the upper head area of the reactor vessel. This indication was observed on plant computer charts for pressurizer level late in the cooldown (just prior to transitioning to shutdown cooling). The steam void was collapsed prior to transitioning to shutdown cooling. A steam void can form in the reactor vessel head during natural circulation cooldown because natural circulation provides very little flow near the reactor head region; the residual heat in the thick metal vessel head can cause the stagnant reactor coolant in that area to reach saturation conditions and create some steam voiding. The background documentation for the natural circulation cooldown procedure indicated that a steam void in the upper region of the reactor vessel head does not represent a challenge to plant safety. The inspectors reviewed the plant computer charts for hot leg and cold leg temperatures (indications of natural circulation), the natural circulation cooldown procedure, and the background documentation for the emergency procedures to assess whether the control room operators appropriately monitored and controlled the plant during the cooldown. The inspectors concluded that the operators appropriately implemented the natural circulation cooldown procedure EMG ES-04.

The team determined that overall, the operating crew performed adequately to stabilize the plant, minimize potential dangers due to the prolonged LOOP, established critical parameter limits for systems required for safe shutdown, and safely conducted a natural circulation cooldown. Once offsite power was restored, the crew safely completed a transition to shutdown cooling and maintained the plant in a cold shutdown condition.

The team also reviewed the control rooms event classification and reporting and determined that the operating crew was both timely and accurate in their reporting of the Notification of Unusual Event to local, state, and federal entities.

3.0 Assess Procedures (Charter Item #3)

a.

Inspection Scope The team reviewed the plant operating and emergency response procedures used to respond to the event. The review focused on the adequacy of procedural guidance and whether operator training supported use and knowledge base of the emergency operating procedures. The team performed operator interviews and a review of the procedures operators marked up during the event, written operator statements, and the

Enclosure post-trip review to assess the procedures.

b.

Observations The team determined that overall, licensee procedure use and adherence was adequate to respond to the event. The licensee entered the correct emergency response procedure and made the required transitions to subsequent emergency procedures and functional restoration guidelines. The team determined that the procedure guidance during the event was adequate to place the plant in a safe and stable condition. The team identified procedure issues associated with the temporary diesel fire pump which are discussed in Section 9 of this report.

4.0 Plant Response (Charter Item #4)

a.

Inspection Scope The team assessed whether plant systems responded as expected by comparing the actual plant response to its design and the applicable safety analyses.

The team reviewed the final safety analysis report (FSAR) Chapter 15, Accident Analysis, section 15.2.6, Loss of Non-Emergency AC Power to the Station Auxiliaries (Blackout). The team reviewed the assumptions in the accident analysis and compared these assumptions to the actual plant response to determine if an unanalyzed condition existed. The team reviewed the initial plant conditions and compared them to the worst-case plant conditions assumed in the accident analysis to determine if the accident analysis remained valid to bound the event.

b.

Observations The team determined that the plant responded as designed, that all assumptions in the accident analysis appropriately bounded the event, and that no unanalyzed condition was identified for this event. The team verified that all equipment assumed to operate in the LOOP accident analysis started and/or operated as expected to mitigate the event.

The team identified other equipment issues that are discussed in later sections of this report, but these issues did not invalidate the accident analysis. Overall, the team determined that the plant responded within the bounds of the accident analysis and that the core was not adversely affected.

Enclosure 5.0 Turbine-Driven Auxiliary Feedwater Pump (Charter Item #5)

a.

Inspection Scope The team reviewed the licensees efforts to determine the cause of an unexpected mechanical overspeed trip alarm that occurred while securing the pump. The team also assessed whether the licensee had operated the turbine-driven AFW pump in accordance with station procedures and the vendor recommendations.

b.

Observations The team identified two URIs requiring follow-up inspection. One URI involved an apparent maintenance deficiency associated with setting the proper tolerances in the turbine mechanical trip linkage mechanism. The second URI involved the licensees failure to follow vendor recommendations for operating the turbine-driven AFW pump.

Approximately 12.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after the onset of the event, when steam pressure lowered to approximately 60 psi, the operator secured the turbine-driven pump by closing the trip and throttle valve (HIS-312A). At the instant the operator pushed the button on the control board to close the trip and throttle valve, the alarm light indicating a mechanical overspeed trip lit up. This was an unexpected response. Using indications on the control board, the operator was able to verify that an actual overspeed event had not occurred.

An operator responded to the turbine room and verified that the mechanical overspeed linkage had tripped. The operator was able to reset the turbine. This meant that the pump could have been quickly re-started if needed, although the need for this would have been unlikely as the plant was placed on shutdown cooling shortly afterwards.

The licensee determined that the cause of the mechanical overspeed trip was inadequate engagement of the trip tappet nut and head lever. This overlap engagement length was required by procedure to be set between 0.03 and 0.06 inches. After the event, this dimension was determined to be only 0.018 inches. It is likely that the vibration induced by closing the trip and throttle valve caused the tappet nut to disengage with the head lever, thereby allowing the lever to pivot and trip the turbine. It is unlikely that the trip would have occurred if the engagement had been properly set.

The team noted that a similar event occurred at Wolf Creek on November 17, 2009, when the pump mechanical overspeed trip actuated at the time the trip and throttle valve was closed. In response, the licensee had visually checked the engagement of the tappet nut to head lever, noting that it appeared to be within specification. However, visual checks of the engagement length are not precise in determining such a short dimension. The licensee informed the team that it will use more accurate methods in the future.

Based on informal communications, the licensee identified that at least five similar events occurred at other nuclear power plants. In each of these cases, the trip also

Enclosure occurred while closing the trip and throttle valve. The licensee stated that they were unaware of any formal operating experience that would have caused them to revise their maintenance procedures concerning the overspeed mechanism.

The team considered the possibility that a spurious trip of the mechanical overspeed device could have occurred while the pump was running in a steady-state condition. Had this occurred during the first few hours of the event, it would have added significantly to the risk. However, the vibration induced by closing the trip and throttle valve is far greater than what is experienced during normal operation. Given this fact and the operating history of other similar turbines, the team concluded that it would have been unlikely that the as-found under-specification condition would have interrupted normal pump operation.

The team also considered the possibility that a seismic event could have caused an inadvertent trip of the turbine due to this existing problem, since seismic events can also cause a LOOP. In that situation, if the emergency diesel generators both fail to operate and AC power cannot be restored quickly, operators would need to reset and re-start the turbine within an hour to prevent core damage. The licensee demonstrated that this could quickly be done.

The team concluded that it was likely that the tappet nut to head lever engagement length was below specification for an extended period of time. The engagement length was checked only during refueling outages; the most recent check was in spring 2011.

However, because the measurement methods used at that time were imprecise, it was likely that the under-engagement condition existed at that time as well. The overspeed trip event in November 2009 suggested that the engagement length at that time might also have been less than specified. The team noted that a test of the overspeed trip was conducted on May 23, 2011, with satisfactory results.

In response to this event, the licensee decided to replace the trip tappet nut, trip lever, and trip linkage spring as well as to inspect all wear points on the trip linkage for damage or wear. The licensee stated that the engagement of the tappet nut to the head lever would be restored to the required specification before plant start-up.

Considering the fact that the turbine-driven AFW pump ran successfully for 12.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months and that the mechanical overspeed trip occurred only as a consequence of securing the turbine, the contribution to the overall risk of the LOOP event was considered to be very low. On the other hand, as discussed above, it was not immediately certain if there was an on-going risk associated with seismic events.

The team determined that the out-of-specification tappet nut to head lever engagement of the turbine-driven AFW pump mechanical overspeed trip mechanism warranted additional NRC review and follow-up considering that this maintenance deficiency led directly to the spurious overspeed trip following the LOOP event and additionally might have affected the reliability of the turbine during a seismic event. Additional review by the NRC will be needed to determine whether this issue represents a performance deficiency. The issue will be identified as URI 05000482/2012008-03, Review Turbine-

Enclosure Driven Auxiliary Feedwater Pump Mechanical Overspeed Trip Device Out of Specification.

The team identified a separate concern with the way the turbine-driven AFW pump was operated during the event in that it was run at low steam supply pressures and at a low speed. At the time the pump was secured, the steam pressure was approximately 60 psig. The Terry Turbine Users Manual specified operating the pump with a minimum steam supply pressure of 77 psig. The team determined that this vendor guidance, as well as previous operating experience on this issue, was not successfully incorporated into licensee procedures and training. Previous testing of a similar turbine-driven pump demonstrated that high axial loading occurred on the pump outboard thrust bearing when turbine speed was in the range of 1600 to 1900 rpm. During the Wolf Creek event, the turbine was operated in this range for approximately one hour.

Also, there was a precaution for running the turbine-driven pump at low flows in Procedure SYS AL120, Motor-Driven or Turbine-Driven Pump Operations, Revision 41, which was dated December 19, 2011, and in effect at the time of the event. It stated:

Operations of the TDAFWP at flow rates less than 175,000 lbm/hr. should be minimized, due to low flow cavitation concerns.

This precaution was not observed during the event. The flow rate cycled above and below this value over almost the entire 12.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months of pump operation. Cumulatively, the pump ran for approximately 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months at a flow rate below 175,000 lbm/hr. The licensee informed the team that it will review the vendor recommendations for turbine operations to determine if changes are needed to procedures or training.

After the event, the licensee removed and inspected the pump outboard thrust bearing.

Although they found no signs of damage, the licensee conservatively replaced the bearing. The team also examined the bearing and observed no signs of damage or wear.

The team determined that the operation of the turbine-driven AFW pump in a manner contrary to vendor recommendations and site procedures warranted additional NRC review and follow-up. Additional review by the NRC will be needed to determine whether this issue represents a performance deficiency. The issue will be identified as URI 05000482/2012008-04, Review Operation of the Turbine-Driven Auxiliary Feedwater Pump at Low Flow, Steam Pressures, and Speed.

6.0 Emergency Diesel Generator B Ground (Charter Item #6)

a.

Inspection Scope The team reviewed licensee efforts to determine the cause of the field ground on the B emergency diesel generator, and to determine whether the ground would have impacted the ability of the generator to perform reliably through its design mission time.

Enclosure The team reviewed the equipment testing, calibration, and troubleshooting procedures used to determine if there was a ground on the generator field or if there was an instrumentation error. The team:

Reviewed condition reports, work orders, and the licensees troubleshooting plan generated during the testing of the generator Reviewed the licensees application of operating experience that was related to generator field grounds, including consultation with Fairbanks-Morse, the vendor of the generator Interviewed licensee engineering staff to discuss the troubleshooting plan and the schedule to perform the troubleshooting Evaluated whether the field ground would impact the ability of the generator to perform reliably through its design mission time

b.

Observations The team identified one URI requiring follow-up inspection. The URI involves determining whether the generator field ground would have impacted the ability of the generator to perform reliably through its design mission time.

The B emergency diesel generator started as required at 2:03 p.m. on January 13, 2012, in response to the LOOP event. At 12:36 p.m. on January 14, while the generator continued to operate, a generator trouble alarm was received in the control room. The local operator reported that a Generator Field Ground annunciator was lit on the local control panel. No change in generator current, voltage or frequency was observed after the alarm was received. The generator had been operating for 22.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months when the alarm came in and continued to operate normally for another 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months until it was no longer needed. Prior to securing the generator, voltage measurements were taken on the relay input terminals which confirmed that a field ground existed.

Using a process of elimination, the licensee isolated the ground to one of four cables between the collector rings on the rotor and the poles inside the generator. When the bad cable was disconnected, the ground went away. The licensee planned to replace all four cables on the generator.

A URI will be opened to evaluate the cause and corrective actions for the ground as well as whether the generator field ground would have impacted the ability of the generator to perform reliably through its design mission time. This issue will be identified as URI 05000482/2012008-005, Assess Impact of Emergency Diesel Generator Ground on Mission Time.

Enclosure 7.0 Essential Service Water System Water Hammer and Leak (Charter Item #7)

a.

Inspection Scope The team reviewed the licensees past and proposed future actions to address the recurrent water hammer events that have challenged the essential service water (ESW) system, and the scope and results of the licensees non-destructive examination of ESW piping to identify areas of pipe thinning or pitting corrosion. The team also examined the leak in ESW piping that was found during a post-trip walkdown.

b.

Observations The team identified two URIs requiring follow-up inspection. One URI involved reviewing the adequacy of licensee corrective actions to mitigate a long-standing history of water hammer events in the ESW system. The second URI involved reviewing the extent of pipe wall-thickness examinations performed to ensure the operability of the ESW system.

Soon after offsite power was lost, the licensee identified a 5 gpm leak in the ESW system 8-inch piping to the train C containment cooler. The source of the leak was discovered during a post-trip containment walkdown and was isolated approximately 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months and 45 minutes after the LOOP occurred. The leak resulted in a total inventory loss of approximately 900 gallons, most of which drained to the containment sump. The ESW design specification for allowable leakage is 140 gpm; therefore, the leak was not large enough to challenge ESW system operability.

The ESW system is an open loop system and uses the ultimate heat sink (i.e., the lake) as its source of inventory. After the leak was isolated, the Train C containment cooler was declared inoperable. A follow-up inspection revealed no additional leaks in the ESW piping.

The licensee assumed that a water hammer event occurred and that it was the direct cause for the leak, such that the resulting pressure pulse failed an area of pipe weakened by pitting corrosion. The presence of staining on the exterior of the pipe at the location of the hole indicated that a small leak was likely present prior to the event, and the water hammer presumably caused the leak rate to increase. The staining was under insulation and therefore not readily apparent.

The water hammer resulted from water column separation in the high elevation portions of the ESW piping supply to the containment coolers. This occurred after the normal service water pumps stopped as a result of a loss of power to the non-safety buses. The two ESW pumps started at approximately 29 and 33 seconds after the LOOP. Once the ESW pumps started, the water columns quickly came back together causing a large pressure spike.

Enclosure Water hammer events in the ESW system have occurred since initial plant start-up, but they did not receive significant attention from the licensee until April 2008, when the issue was raised by the NRC resident inspectors.

The licensee stated that an evaluation will be performed to identify modifications to mitigate the occurrences and magnitude of water hammer events in the ESW system.

This strategy might include the use of check valves, surge tanks, or vacuum breakers.

The licensee stated that these modifications would most likely be installed during refueling outage RF20 in the spring of 2014. Because water hammer events have been a long-standing problem in the ESW system, the team was concerned that the actions to correct this problem have not been timely.

The team determined that the licensees efforts to correct a water hammer problem in the ESW system warranted additional NRC review and follow-up because this phenomenon has repetitively challenged the integrity of a risk-significant safety-related system. Additional review by the NRC is needed to determine whether this issue represents a performance deficiency. This issue will be identified as URI 05000482/2012008-06, Review Actions to Correct Water Hammer Events in the ESW System.

The team reviewed licensees efforts to identify areas of pitting corrosion in the ESW piping. Based on previous leaks and acknowledgement of the corrosion potential of this piping, the licensee had performed inspections of various sections of piping. The inspection methods included guided wave and phased array or single transducer ultrasonic testing (UT).

The areas of piping not previously inspected by the licensee were reviewed by the team.

Some of the ESW piping leading up to and connecting to the containment coolers had not been inspected based on engineering judgment that these sections of piping were not especially vulnerable to pitting corrosion. Any piping that was provided by a vendor (e.g., was skid-mounted) had been considered by the licensee to be outside the scope of their inspection. The section of piping that failed was in a vendor-supplied 8-inch line associated with the train C containment cooler which had not been previously inspected.

Also not inspected were some areas of piping that were inaccessible for UT measurement, including containment penetrations, piping under support clamps, areas obstructed by permanently-installed plant equipment, and valve bodies.

The ESW system piping had experienced an increasing number of leaks in recent years.

The following is an excerpt from the executive summary in IIT 10-01, Investigation Into the Material Condition of ESW Piping and Events From CR 00026466 and CR 00028474, issued in November 2010:

Wolf Creek Generating Station has experienced five ESW system through-wall pipe leaks since June 2009. The first four leaks were on exposed pipe and accessible for repair. The fifth leak in October 2010 was in underground ESW pipe and considerably less manageable to repair. The station has experienced a significant recent increase in the number of ESW through-wall pipe leaks. In

Enclosure addition to pipe leakage, the ESW system is subject to column closure water hammer events during ESFAS actuations. The effects of repeat water hammer events, combined with through-wall pipe leaks, have not been fully evaluated.

The team determined that previous efforts were not sufficient to detect corrosion problems before they developed into leaks and that water hammer events made leaks more likely. The team determined that the licensees failure to examine the condition of vendor-supplied piping associated with the containment coolers as well as other areas of ESW piping warranted additional NRC review and follow-up. Additional review by the NRC will be needed to determine whether the licensees limited scope of piping inspection represents a performance deficiency. This issue will be identified as URI 05000482/2012008-07, Review ESW Piping Corrosion Inspections.

In response to this event, the licensee conducted additional inspections of the ESW piping, including the vendor-supplied piping connected to the containment coolers.

Based on the results, sections of piping associated with the train A and train B containment coolers were replaced as well as the section that contained the leak in the train C piping.

The licensee informed the team that all accessible ESW piping inside containment and all ESW piping outside containment that was 6 or larger had been or will be inspected prior to plant start-up. Some areas of piping outside containment under 6 will not be inspected before plant startup, though some of this piping is scheduled to be inspected either during the spring of 2012 or in refueling outage RF19 in the fall of 2012. The total length of small-bore ESW piping that will remain uninspected is approximately 1700 feet.

The licensee explained that small bore piping was less likely to suffer pitting corrosion, the consequences of leaks of this size are less severe, and leaks in this piping are more easily isolated. The licensee stated that piping with stagnant water or low flow velocities was more likely to have pitting corrosion, and that much of the piping that will not be inspected prior to plant startup had high flow rates. Additionally, some piping was not inspected because of its location in high radiation areas; though in these cases, pipe runs leading up to these rooms were inspected and shown to be relatively corrosion free, giving some confidence that the piping within the radiation areas were similarly in good condition.

The licensee used a calculation of the maximum pressure induced by postulated water hammers to determine the minimum acceptable wall thickness for its ultrasonic testing program. An assumed corrosion rate of 0.05 inches per year is then applied and this information is used to determine the time until a leak is expected for a given problem area. These areas are then scheduled to be inspected again before the leak is projected to occur.

None of the buried piping had been or will be inspected by ultrasonic or guided wave inspections before plant start-up, but all of it was scheduled to be replaced during refueling outage RF20 in the spring of 2014. In the interim, the licensee is monitoring the underground piping by visual over-ground inspections as well as by use of ground penetrating radar. In October 2010, a 40-50 gpm leak developed in the underground

Enclosure piping. The licensee stated that the ground penetrating radar was able to detect the leak, giving confidence in the effectiveness of this diagnostic tool.

8.0 Source Range Nuclear Instrument Deviation (Charter Item #8)

a.

Inspection Scope The team assessed the impact of the deviation between the two source range nuclear instrument channels on operator decision-making, and the ability to verify that adequate shutdown margin existed. The team also assessed the timeliness of the licensees cause assessment and corrective action for this condition, which has existed since 2009.

The team reviewed the plant computer charts for the source range nuclear instruments, various engineering evaluations, technical specifications and bases, and interviewed subject matter experts in engineering and maintenance. The team also verified that shutdown margin calculations were performed and reported to the control room staff prior to commencing a natural circulation cooldown. Additionally, the team reviewed corrective actions and testing performed following the 2009 LOOP event and 2011 loss of cavity cooling events. The team discussed the testing and actions planned to address the detector deviation prior to reactor startup.

b.

Observations The team identified one URI associated with the source range nuclear instrument NI-31 diverging indication during the LOOP event and resultant loss of reactor cavity cooling.

The URI will determine whether corrective actions, commensurate with its safety significance, have been appropriate and timely since identifying the issue during the 2009 LOOP event.

In August 2009, the Wolf Creek facility experienced a LOOP as a result of a lightning strike on the electrical distribution system. The LOOP resulted in the loss of reactor cavity cooling fans that circulate cool air to the source range nuclear instrument detectors and cables. As temperatures increased around the detectors, NI-31 counts began to increase, while NI-32 continued to trend downward as expected. The licensee was able to restore cavity cooling after offsite power was restored and NI-31 counts began to lower and returned to proper indication.

Following the 2009 LOOP event, the licensee replaced both source range detectors and cables during refueling outage RF17 in October 2009. In March 2011, another loss of reactor cavity cooling occurred and NI-31 counts again began to increase, while NI-32 remained unchanged. Once cavity cooling was restored the counts associated with NI-31 returned to expected indications, consistent with NI-32. For both the 2009 and 2011 events, loss of reactor cavity cooling caused NI-31 counts to increase, and restoration of normal reactor cavity cooling caused counts to return to expected indicated levels. The licensee concluded that the increasing counts are linked to ambient temperature rise at NI-31 that occurs when reactor cavity cooling is lost.

Enclosure The licensee performed engineering evaluations SWO 11-341977 and WO 11-339015-004 to document the events and the justification for operation until the cause of the elevated ambient temperature at NI-31 can be identified and corrected.

During the January 13, 2012, LOOP event and subsequent loss of cavity cooling, NI-31 counts began to increase as in the previous events. The crew recognized the increasing counts and declared the detector inoperable. Technical Requirements Manual bases document B3.3.15, Source Range Neutron Flux, allows for use of the Gamma Metrics detectors to provide source range indication when rods are not capable of withdrawal.

The operating crew confirmed the Gamma Metrics detectors were indicating properly, and relied upon them in place of the source range detectors.

The licensee performed another engineering evaluation to document the increasing counts following the recent LOOP event, and to document that SENI0031 should continue to be considered degraded because of its abnormal response to loss of cavity cooling which SENI0032 does not experience. The licensee was tracking this condition using condition reports 35122 and 47652.

The team assessed the impact of the diverging source range detector on the operating crews decision-making and determined that the crew recognized the trend as erroneous based on previously documented occurrences. The crew then relied upon NI-32 and the Gamma Metrics detectors to verify proper shutdown conditions. The inspectors assessed the impact on the licensees ability to verify adequate shutdown margin and determined that the source range detectors are not used as an input into the shutdown margin calculation. The team verified that the crew obtained a shutdown margin calculation supporting cooldown to 150 degrees F prior to commencing the natural circulation cooldown.

A limited area visual inspection was performed prior to the team leaving site, but did not reveal any obvious causes for elevated temperatures. Further investigation by the licensee was ongoing at the conclusion of the inspection.

Prior to plant startup following the LOOP event, the licensee planned to perform:

(1) cavity cooling ventilation flow and temperature measurements, (2) detector well ventilation leak checks on both source range detectors and perform visual inspection of the detector well inlet scoop, (3) heat the detector junction box to assess whether the cable heating was the cause, and (4) as a planned contingency, install temperature monitors to the detector well.

The team questioned whether the corrective actions taken during the prolonged time from the initial occurrence in 2009 until the current LOOP event in January 2012 were adequate and timely, commensurate with its safety significance. This issue will be identified as URI 05000482/2012008-08, Review Source Range Detector Deviation.

9.0 Temporary Fire Pump (Charter Item #9)

a.

Inspection Scope

Enclosure The team evaluated: (1) the cause of the failure of the normal diesel-driven fire pump; (2) the adequacy of the temporary modification to be able to meet the design and licensing basis requirements for the system; (3) the adequacy of the actual installation and operating procedures, including suction source, weather protection, minimum flow design, and the ability to maintain system pressure during a prolonged loss of power; and (4) the sequence of events that led to subsequent temporary pump failure when the motor-driven fire pump was returned to service. The team reviewed drawings, condition reports, work orders, operating experience, testing procedures, oil samples, modification packages, operating procedures, and logs and also conducted walkdowns and operator interviews.

b.

Observations The team identified three URIs associated with: (1) failure to maintain fire water pressure for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months , (2) the adequacy of the actual installation and operating procedures of the temporary diesel-driven fire pump, and (3) the adequacy of the temporary modifications to be able to meet design and licensing requirements. In addition, the team identified one URI associated with the initial cause of the 2011 failure of the installed diesel-driven fire pump, which is discussed in detail in Section 10 of this report.

=

System Description===

The Wolf Creek water-supplied fire protection system takes its suction from the Wolf Creek cooling lake and includes an electric motor-driven jockey pump, an electric motor-driven fire pump and a diesel-driven fire pump. The pumps and their controls are located in the circulating water screen house by the lake.

The design of the water-supplied fire protection system is such that normal header pressure is maintained by the jockey pump from the service water system. The primary purpose of the jockey pump is to compensate for small leaks and demands on the fire header system without having to start the much larger motor-driven fire pump, which is sized to supply all fire water for the plant. The electric motor-driven fire pump will automatically start on a drop in header pressure below 115 psi, which is below the start pressure for the jockey pump. The installed diesel-driven fire pump will auto start on a drop in header pressure below 105 psi and is designed to automatically start utilizing batteries in response to a LOOP.

The water-supplied fire protection system is a non-safety-related system and is supplied power from the non-safety-related busses PA001 and PA002. When the January 13, 2012, LOOP event occurred, power was lost to both the jockey pump and the motor-driven fire pump. The design of the system is such that the installed diesel-driven fire pump would have started in response to the LOOP, except that it had been out of service since September 13, 2011, when it had catastrophically failed during its monthly functionality test. As a compensatory measure for the out-of-service diesel-driven fire pump, a temporary diesel-driven fire pump had been installed in accordance with the

Enclosure plant fire protection impairment program, AP 10-103, Section C.1.3.C.2.

The temporary diesel fire pump was a packaged trailer-mounted unit that took a direct suction from the cooling lake. The temporary diesel fire pump was manually operated with no auto-start capability. The packaged system was provided with manually operated priming pumps mounted on the trailer for priming the main pump. The diesel engine can be started once the main pump is primed, then distribution valves and minimum flow line valve have to be aligned. The unit was provided with an inline check valve, a fitting for external priming, and a minimum flow line. At the time of the LOOP the pump suction, pump case, minimum flow line, discharge manifold, and pump discharge lines had been drained to prevent freezing. Without power to the motor-driven fire pumps (because of the LOOP), and with the temporary diesel fire pump drained, Wolf Creek was left without fire protection water pressure until an operator was available and the temporary diesel-driven fire pump could be manually primed, started, and aligned to the fire main header. On the day of the LOOP, because of complications described below, it took 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months to get the temporary diesel-driven fire pump in service and supplying pressure to the fire header.

Sequence of Events At 3:00 p.m., about 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months into the LOOP on January 13, 2012, the plant fire protection supervisor informed the control room that the station did not have fire suppression water pressure. In accordance with the fire protection impairment program, AP 10-103, Attachment C.1.3.1.E.1, with two fire pumps inoperable, the required action is to provide a backup fire pump within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Operators were directed to put the temporary diesel-driven fire pump into service using procedure SYS FP-290 Temporary Fire Pump Operations, Revision 12. Operators made numerous attempts to prime the temporary diesel-driven fire pump, but they were initially unsuccessful in priming the pump, in part, because they did not shut the drain valves on the suction manifold. Procedure SYS FP-290 did not have adequate instructions and the pump skid did not have adequate labeling to support closing pump suction manifold drain valves. In addition, Figure 1 of this procedure, which was supposed to represent the installation, did not show any of the drain valves or the installed check valve that were part of the system. In interviews with licensee staff it was determined that operators were given on-the-job training on operation of the temporary diesel-driven fire pump in the fall of 2011, but no lesson plan was used and some operators had only one attempt with starting the equipment.

Operators eventually located and closed the suction manifold drain valve that was open and were successful in priming the temporary diesel-driven fire pump; however, because of the inadequate procedure, training, and equipment labeling, and other equipment issues, operators did not get the temporary diesel-driven fire pump primed, started, and supplying fire header pressure until 11:00 p.m., which left Wolf Creek without fire suppression water pressure for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months .

Summary of Issues There were several factors that delayed the successful operation of the temporary

Enclosure diesel-driven fire pump on the day of the LOOP. They are listed as follows:

The control room did not give starting the pump a high priority.

The installation and location of the pump was such that it was not protected from freezing and had to be kept drained. It also had to be primed and started manually.

The procedures to put the pump in operation were not adequate.

The labeling of equipment that required alignment on the temporary fire pump was not adequate.

The priming equipment failed due to prolonged operation.

The training for operators was inadequate.

The lighting conditions were poor.

The combination of these events resulted in the temporary pump not being placed into service for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months . A URI will be opened for the failure to maintain fire water pressure for the first 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months of this event. This issue will be identified as URI 05000482/2012008-09, Review Failure to Maintain Fire Water Pressure.

Plant procedure SYS FP-290, Temporary Fire Pump Operations, Revision 12, did not provide adequate instructions on how to prime and start the temporary diesel-driven fire pump. Valves that were required to be in a certain state were not detailed enough or labeled such that operators could place the equipment in the proper alignment to successfully prime and start the pump. In addition, the drawing that is supposed to show the installation of the temporary diesel-driven fire pump was missing key components that were required to be manipulated in order to put the pump in service.

Operators were only given on-the-job training on this temporary pump with no lesson plan to follow and with minimal practice with the unit. A URI will be opened for failure to provide adequate procedures and training for the proper priming and startup of the temporary diesel-driven fire pump. This issue will be identified as URI 05000482/2012008-10, Review Inadequate Procedures and Training for Operation of the Temporary Diesel Fire Pump.

The temporary diesel-driven fire pump was not functionally identical to the original diesel-driven fire pump since it could not start automatically and provide the required backup to the electric motor-driven pump in the event of a LOOP, as the original diesel-driven fire pump was designed to do. This issue will be identified as URI 05000482/2012008-11, Assess Impact of Failure of Temporary Pump to Match the Functionality of Diesel Fire Pump.

10.0 Past Maintenance Impact (Charter Item #10)

a.

Inspection Scope The team conducted an overall review of the licensees maintenance practices to determine if past maintenance activities could have contributed to the event, or impacted the response and recovery.

Enclosure The team reviewed the sequence of events to determine which components did not perform as expected or performed poorly to determine the systems on which to focus.

The team reviewed the maintenance history associated with these systems. The team also reviewed the updated final safety analysis report, technical specifications, system health reports, quality audits, design basis documents, condition reports, and interviewed personnel to verify that appropriate performance criteria were being monitored and maintained. The team also reviewed the technical adequacy of any evaluations associated with these systems to ensure that technical specification operability was properly justified.

b.

Observations The team identified one URI requiring follow-up inspection associated with determining whether the September 13, 2011, failure of the normal diesel fire pump was maintenance-related.

The team determined that past maintenance-related activities negatively impacted the LOOP response and recovery. Specifically, there were maintenance-related issues previously described in this report associated with the ESW system, the diesel-driven fire pump, the temporary diesel-driven fire pump, the turbine-driven AFW pump, and the carbon dioxide purge system. However, none of these conditions prevented the operating crew from performing a safe and controlled shutdown and cooldown and placing the reactor coolant system into a stable cold shutdown condition (Mode 5) within the required technical specification allowed outage time.

The 2011 failure of the normal diesel-driven fire pump resulted from a catastrophic failure of the pumps right angle drive during the performance of the monthly functionality test for the fire pump. The failed unit had 1060 operating hours (equivalent to 44 days of 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s/day operation) and had been installed for 27 years. The diesel-driven pump right angle drive had had several periodic oil samples that showed evidence of high concentrations of water and iron. These oil samples were taken every six months, and indicate bearing/bushing and shaft/gear wear along with a heavy concentration of water present. The recommended actions were inspection for source of wear may be warranted at this time and check for source of water. The oil cooler for the right angle drive was replaced on August 18, 2011, as it was determined to be the only possible source of the water that continued to show up in the oil samples.

The licensee speculated that the pump seized and caused excessive torque to be placed on the gearbox, which resulted in the gearbox catastrophically failing. The license was having the manufacturer of the pump, Fairbanks-Morse, perform a failure analysis on the pump to determine if the pump caused the failure.

This issue will be identified as URI 05000482/2012008-12, Assess Cause of Normal Diesel Fire Pump Failure.

Enclosure 11.0 Impacts of Prolonged Loss of Offsite Power (Charter Item #11)

a. Inspection Scope The team reviewed licensee actions taken in response to the prolonged LOOP. The following areas were specifically reviewed:

Initial event response and ability of safety-related equipment to continue to function through their full design mission times Timing and capability to cool the plant down to Mode 5, including performing the required chemistry samples Capability to implement the site emergency plan The team conducted interviews with various on-shift personnel and reviewed the post-trip report, which included control room logs, operator statements, and plant data trends.

The review assessed the effectiveness of the procedure guidance in addressing the event and placing and maintaining the plant in a safe and stable condition. The licensee created roll-up condition report 47884 to address concerns about the extended LOOP on non-safety-related equipment.

b. Observations Items that were not previously discussed in this report created additional challenges because of the duration of the LOOP:

All three reactor coolant leakage detection systems were inoperable and resulted in the control room not recognizing a 5 gpm leak into the reactor containment building sump for roughly two and a half hours. Certain components of the leakage detection systems lost power during the LOOP.

This could have resulted in not detecting a reactor coolant system leak within one hour as required by technical specifications; however, the actual leak was not reactor coolant system leakage and was not radioactive. The inspectors determined that the leakage detection systems were installed and operating in accordance with design specifications.

Loss of power to the chemistry hot lab prevented the licensee from analyzing reactor coolant samples normally required for shutdown, but emergency procedures allowed for alternatives to support safe shutdown without power to the chemistry labs. Additionally, the licensee implemented an emergency temporary modification to restore partial power to the chemistry lab. When the team left the site, the licensee was evaluating design changes to ensure that chemistry labs maintain at least partial power through similar events.

Localized flooding could have become a concern since most sump pumps lost power, particularly auxiliary building sump pumps. The licensee recognized this concern and implemented an emergency temporary modification to provide

Enclosure power to the pumps. The licensee also dispatched additional personnel to ensure that the areas were appropriately controlled. When the team left the site, the licensee was evaluating design changes to maintain the pumps energized during LOOP events.

Hydrogen from the main generator was emergency vented to prevent an explosive buildup. If the battery powered seal oil pumps had lost power, a potential fire or explosive environment could have been created in the turbine generator building. The licensee had a procedure for emergency venting of the main generator until CO2 could be delivered to the site. The permanently installed CO2 system has not been functional in several years and has not been a priority for repair. When the team left the site, the licensee was evaluating their position on restoring the installed CO2 system to operational status.

The licensee used emergency temporary modifications to restore power to selected non-safety-related systems by using temporary generators. The licensee staged several temporary generators at various locations around the site to be able to provide power to desired equipment. When the team left the site, the licensee was assessing these modifications for further enhancements to be used in the event of a future LOOP event.

The team determined that overall, safety-related equipment would have continued to operate through their full mission time.

The largest impact from the prolonged loss of power was the number and frequency of samples that chemistry had to perform as a result of losing the radiation monitoring system. The licensee documented this concern in condition report 47884 for further evaluation and determined that it had an adverse operational affect for the plant in that Chemistry could not use their sampling equipment. Additionally, due to the nature of the fault on the main generator breaker, there was a need to promptly purge the hydrogen from the generator. Because Wolf Creek did not maintain their CO2 system functional, they must have a vendor deliver bulk CO2 when needed. They have a procedure to allow emergency venting the majority of the hydrogen until the CO2 can be delivered to allow proper hydrogen purging. This could have been a challenge and could have potentially created an unsafe hydrogen condition had the operating crew not recognized the need to extend the life of the battery that was supplying power to the hydrogen seal oil pumps. The shift manager in discussion with the turbine watch agreed on the need to remove unnecessary loads from the battery to extend its life.

While there were challenges and difficulties as a result of the LOOP, the team determined that it did not impact the timing or capability of the crew to safely stabilize the plant in Mode 5, nor did it significantly impact the ability to take required chemistry samples.

The team also determined that the prolonged LOOP did not impact the ability of the station to implement the site emergency plan. The technical support center and the emergency operating facilities remained energized throughout the entire event from offsite power, and each facility had its own backup diesel generator. The team determined that the operating crew appropriately considered staffing the technical

Enclosure support center, but decided that it would not have added any additional benefit over the manning of the forced outage recovery team that was already occurring. The shift managers office in the control room lost power, but many of those activities were performed from the technical support center. The team determined that this did not prevent any actions from being performed. Emergency sirens remained available throughout the event. All required offsite notifications to state, local, and federal entities were complete, accurate, and accomplished within required timelines.

12.0 Independent Risk Assessment (Charter Item #12)

a.

Inspection Scope The team reviewed the sequence of events and equipment problems to support an independent assessment of the risk of the LOOP event.

b.

Observations The event was modeled as a switchyard-centered LOOP in the initial Management Directive 8.3 risk assessment. Because offsite power was not restored to the safety buses for 3.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , recovery of offsite power was assumed to fail for sequences of 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months or shorter duration. Also, the diesel-powered fire water system was failed, reflecting the 9 hour1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months delay in starting this pump and restoring fire water protection header pressure. These assumptions resulted in an initial conditional core damage probability of 8E-5.

Based on a review of the sequence of events and discussions with operators, the team refined the offsite power recovery assumptions. Because of the complications associated with restoring power to the vital buses, recovery of offsite power within one hour was still assumed to fail. For longer recovery durations (2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and above), the team determined that nominal baseline recoveries for a switchyard-centered LOOP would be appropriate. This was based on crediting the expedited actions that could be have been accomplished if the plant was in a blackout condition (i.e., no emergency diesel generator working).

Shortly after offsite power was lost, power-operated relief valve PCV-456A cycled 23 times during a 15-minute period. The repeated cycles of this valve increased the probability of it sticking open and creating a small-break loss of coolant accident.

Accordingly, the team concluded that the probability of this valve failing to close should be considered to have increased by one order of magnitude. Also, the fact that power-operated relief valve PCV-455A was isolated by its block valve was a valid condition to include in the risk model.

The team concluded that the spurious turbine-driven AFW pump overspeed event did not reflect a need to adjust the baseline reliability of this equipment. This was because the pump ran normally for 12.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months and the trip was strictly a consequence of closing the trip and throttle valve while securing the pump. Also, the fact that the pump was run for several hours with flow dynamics inconsistent with its long-term operation was not a

Enclosure basis for adjusting risk assumptions for this event. As discussed in Section 5, the pump bearings were neither damaged nor experienced any detectable wear. The operation of the pump outside of its normal operating condition was an equipment qualification issue that might affect its long-term operation, but it was not a factor in this event.

The leak in the ESW system was too small to challenge the function of the system, and this was true even if the leak had not been as quickly isolated. The team concluded that the pipe pitting corrosion experienced during recent history was unlikely to produce leaks of a size that could challenge the system function based on historical problems and non-destructive examination results for system piping. The type of corrosion that attacks ESW piping produces localized pits that would be unlikely to result in a catastrophic pipe failure. Accordingly, the team concluded that the ESW system should be assumed to have baseline reliability for this event.

The team found no information to change the initially assumed failure and long-term (9 hour1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months ) unavailability of the diesel-powered fire water pump. It was considered likely that a high priority would have been placed on restoring this pump if a fire had developed, but problems encountered in priming the pump would likely have delayed its restoration to a point where it would not have been made available quickly enough to have mitigated the consequences of a fire.

A senior reactor analyst used the updated assumptions to estimate the risk of the event.

The Wolf Creek SPAR model, Revision 8.5, was used with a truncation of 1.0E-12 and with test and maintenance basic events removed. The resulting conditional core damage probability was 6.2E-5.

Enclosure 13.0 Assess Quality Assurance (QA), Radiological, Security, and Safety Conscious Work Environment (SCWE) Aspects (Charter Item #13)

a.

Inspection Scope The team reviewed the sequence of events, operator actions, management decisions, and equipment problems to determine whether issues existed related to QA, radiological exposure, security, and SCWE.

b.

Observations The team did not identify issues related to QA or radiological conditions.

The team identified a security issue associated with the design of the power supply for some protected area perimeter assessment equipment that was referred to NRC regional experts for follow-up inspection and is identified as URI 05000482/2012008-13, Assess Security Power Supply Anomaly.

14.0 Exit Meeting Summary On March 6, 2012, the NRC held a public meeting and presented the inspection results to Mr. Matthew W. Sunseri and other members of the staff, who acknowledged the observations. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.

A1-1 SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee Personnel:

Bill Ketchum, Supervisor Engineer, Probabilistic Risk Assessment and Safety Analysis Brad Norton, Manager, Engineering Programs Brendan Ryan, Simulator Fidelity Coordinator Brian Schafer, Engineer III Brian Williams, Principal Engineer Carlos Garcia, Supervisor Engineer, System Engineering Carlos Hernandez, Engineer V Charles Medenciy, Health Physics Supervisor Chris Turner, Supervisor Quality Control Curt Palmer, Supervisor Design Engineering Dave Erbe, Manager Security Dave Meredith, Principal Engineer David Alford, Engineer V (Risk)

David Dees, Superintendent Operations David Garrison, Operations Specialist III Diane Hooper, Supervisor Licensing Don Garbe, Engineer V, Fire Protection Don Long, Engineer V Dwight Gerrelts, Principal Engineering Technologist, System Engineering Edward C. Holman, Supervisor Maintenance Francis Brush, Consultant Gerald Riste, Excel Consultant Greg Kinn, Supervisor Nuclear Engineering Jason Cameron, Sr. Nuclear Station Operator Jeff Suter, Supervisor Engineer, Fire Protection Jim Weeks, Principal Engineering Technologist, Modifications Joe Helget, Engineer IV John Broschak, Vice President Engineering Josh Turner, Engineering Technologist IV Justin Keim, Supervisor Engineer Kevin Hermreck, Master Mechanic Lou Solorio, Engineer V Mark Ferrel, Supervisor Engineer, Engineering Programs Mark Jenkins, Shift Manager Martin Rabalais, Engineer V Matt LeGresley, Engineer II, System Engineering Neil Woydziak, Acting Manager, Chemistry Paul Adam, Principal Engineer Preston Lawson, Surveillance Coordinator, Operations Randy Birk, Superintendent Maintenance Reece Hobby, Licensing Engineer III Rodney Wolfe, Operations Apprentice III

A1-2 Robert Wisdom, Planner Rich Clemens, Vice President Strategic Projects Rich Flannigan, Manager Nuclear Engineering Scott Good, Supervisor Security Support Scott Maglio, Manager Regulatory Affairs - Callaway (STARS)

Seth Bell, Control Room Supervisor and Shift Technical Advisor Shafayet Hossain, Engineer III Stan Devena, Engineer Steve Ernest, Principal Engineer Technologist Steve Henry, Operations Manager Steve Hopkins, Supervisor Maintenance Steve Wideman, Principal Licensing Engineer Tiffany Baban, Manager, System Engineering Tim Dunlop, Control Room Supervisor Tracy Fisher, Supervisor Maintenance William Muilenburg, Licensing Engineer V NRC personnel:

Christopher Long, Senior Resident Inspector Charles Peabody, Resident Inspector LIST OF ITEMS OPENED 05000482/2012008-01 URI Review Main Generator Output Breaker Fault Cause (Section 1.2)05000482/2012008-02 URI Review Startup Transformer Fault Cause (Section 1.2)05000482/2012008-03 URI Review Turbine-Driven Auxiliary Feedwater Pump Mechanical Overspeed Trip Device out of Specification (Section 5.0)05000482/2012008-04 URI Review Operation of the Turbine-Driven Auxiliary Feedwater Pump at Low Flow, Steam Pressures, and Speed (Section 5.0)05000482/2012008-05 URI Assess Impact of Emergency Diesel Generator Ground on Mission Time (Section 6.0)05000482/2012008-06 URI Review Actions to Correct Water Hammer Events in the ESW System (Section 7.0)05000482/2012008-07 URI Review ESW Piping Corrosion Inspections (Section 7.0)05000482/2012008-08 URI Review Source Range Detector Deviation (Section 8.0)

A1-3 05000482/2012008-09 URI Review Failure to Maintain Fire Water Pressure (Section 9.0)05000482/2012008-10 URI Review Inadequate Procedures and Training for Operation of the Temporary Diesel Fire Pump (Section 9.0)05000482/2012008-11 URI Assess Impact of Failure of Temporary Pump to Match the Functionality of Diesel Fire Pump (Section 9.0)05000482/2012008-12 URI Assess Cause of Normal Diesel Fire Pump Failure (Section 10.0)05000482/2012008-13 URI Assess Security Power Supply Anomaly (Section 13.0)

LIST OF DOCUMENTS REVIEWED DRAWINGS Number Title Revision E-02PA01 LOGIC DIAGRAM UNIT AUXILIARY SOURCE 13.8 KV BUS FEEDER BREAKERS 4

E-12PA02 LOGIC DIAGRAM STARTUP SOURCE 13.8 KV BUS FEEDER BREAKERS 0

E-13KJ02 SCHEMATIC DIAGRAM DIESEL GENERATOR KKJ01A ANNUNCIATOR AND MISCELLANEOUS CIRCUITS 7

E-13KJ04 SCHEMATIC DIAGRAM DIESEL GENERATOR KKJ01B ANNUNCIATOR AND MISCELLANEOUS CIRCUITS 8

E-13MR01 STARTUP TRANSFORMER THREE LINE DIAGRAM 3

E-13NB05 LOWER MEDIUM VOLTAGE SYS. CLASS 1E 4.16 KV THREE LINE METER AND RELAY DIAGRAM 2

E-13NE02 STANDBY GENERATION SYSTEM THREE LINE METER AND RELAY DIAGRAM 14 E-13PA03 HIGHER MEDIUM VOLTAGE SYSTEM 13.8 KV THREE LINE METER AND RELAY DIAGRAM 1

E-13PA04 HIGHER MEDIUM VOLTAGE SYSTEM 13.8 KV THREE LINE METER AND RELAY DIAGRAM 1

KD-7496 ONE LINE DIAGRAM 41

A1-4 Number Title Revision KD-7496A DISTRIBUTION SYSTEM EQUIPMENT LINEUP LIMITATIONS 5

M-0023 SHEET 1 PIPING & INSTRUMENTATION DIAGRAM FIRE PROTECTION SYSTEM (FP) 53 M-0023 SHEET 2 PIPING & INSTRUMENTATION DIAGRAM FIRE PROTECTION SYSTEM (FP) 20 M-0023 SHEET 3 PIPING & INSTRUMENTATION DIAGRAM FIRE PROTECTION SYSTEM (FP) 33 M-0023 SHEET 4 SARGENTY AND LUNDY PIPING & INSTRUMENTATION DIAGRAM FIRE PROTECTION SYSTEM (FP) 15 M-018-00076 BELOIT POWER SYSTEMS ELECTRICAL SCHEMATIC DIESEL GENERATOR CONTROL NE107 (NE106) 14 M-018-00077 SHEET 1 BELOIT POWER SYSTEMS ELECTRICAL SCHEMATIC DIESEL GENERATOR CONTROL NE107 (NE106)

W17 M-018-00110 SHEET 6/11 BELOIT POWER SYSTEMS ELECTRICAL SCHEMATIC ENGINE GAUGE PANEL KJ121 (KJ122)

W13 M-018-00250 SHEET 1 BELOIT POWER SYSTEMS WIRING DIAGRAM GENERATOR CONTROL PANEL (NE107)

W15 M-018-00250 SHEET 2 BELOIT POWER SYSTEMS WIRING DIAGRAM GENERATOR CONTROL PANEL (NE106)

W03 M-018-00251 SHEET 1 BELOIT POWER SYSTEMS WIRING DIAGRAM GENERATOR CONTROL PANEL W13 M-018-00635 WESTINGHOUSE ELECTRIC CORPORATION COLT INDUSTRIES TYPE WNR VOLTAGE REGULATOR AND EXCITATION SYSTEM EXCITATION SCHEMATIC W02 M-018-00688 SHEET 1 BELOIT POWER SYSTEMS ASSEMBLY DRAWING GENERAL CONTROL AND RELAY PANEL NE107 (NE106)

W09 M-13EF09(Q)

SMALL PIPING ISOMETRIC ESSENTIAL SERVICE WATER SYSTEM AUX. BLDG. A TRAIN SUPPLY AND RETURN 0

M-13EF10 SMALL PIPE ISOMETRIC ESSENTIAL SERVICE WTR. PIPE CHASE VENTS & DRAINS TRAIN B AUXILIARY BUILDING 4

M-13EF11 SMALL PIPE ISOMETRIC ESSENTIAL SERVICE WTR. PIPE CHASE VENTS & DRAINS TRAIN A AUXILIARY BUILDING 1

M-13EF12(Q)

PIPING ISOMETRIC ESSENTIAL SERVICE WATER FUEL BUILDING 5

A1-5 Number Title Revision M-13EF13 SMALL PIPING ISOMETRIC MISCELLANEOUS DETAILS ESSENTIAL SERVICE WATER SYSTEM 8

M-13EF16 PIPING ISOMETRIC ESSENTIAL SERVICE WATER SYSTEM TURBINE BUILDING 4

M-13EF17 PIPING ISOMETRIC ESSENTIAL SERVICE WATER SYSTEM TURBINE BUILDING 1

M-15EF01(Q)

HANGER LOCATION DWG. ESSENTIAL SERVICE WATER CONTROL BLDG. (A&B) TRAIN 6

M-15EF02 HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYSTEM AUX. BLDG. A TRAIN SUPPLY 25 M-15EF03 HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYSTEM AUX. BLDG. A TRAIN RETURN 18 M-15EF04(Q)

HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYS. AUX. BLDG. B TRAIN SUPPLY 8

M-15EF05 HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYS. AUX. BLDG. B TRAIN RETURN 16 M-15EF06 HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYS. AUX. BLDG. A&B TRAIN SUPPLY AND RETURN 19 M-15EF07(Q)

HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYSTEM CONTROL BLDG. COOLER (A&B) TRAIN SUPPLY RTN.

4 M-15EF08 HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYSTEM DIESEL GENERATOR BLDG.

7 M-15EF14 HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYS. CLASS 1E SWITCHGEAR A/C COND. CONTROL A TRAIN 9

M-15EF15 HANGER LOCATION DWG. ESSENTIAL SERVICE WATER SYS. CLASS 1E SWITCHGEAR A/C COND. CONTROL B TRAIN 3

M-15GN01 HANGER LOCATION DWG. CONTAINMENT COOLING SYSTEM REACTOR BUILDING TRAIN A 6

M-15GN02 LOCATION DWG. CONTAINMENT COOLING SYSTEM REACTOR BUILDING TRAIN B 6

M-K2EF01 PIPING AND INSTRUMENTATION DIAGRAM ESSENTIAL SERVICE WATER SYSTEM 57

A1-6 Number Title Revision M-K2EF03 PIPING AND INSTRUMENTATION DIAGRAM ESSENTIAL SERVICE WATER SYSTEM 11 SK2131 SHEET 1 OF 2 WESTAR ENERGY BENTON SUBSTATION ONE-LINE DIAGRAM (BENT) 4 SK9392 SHEET 1 OF 3 WESTAR ENERGY ROSE HILL SUBSTATION ONE-LINE DIAGRAM (ROSE) 3 PROCEDURES Number Title Revision AP 02-007 ABNORMAL CONDITIONS GUIDELINES 13 AP 02A-001 PRIMARY CHEMISTRY CONTROL 15A AP 10-103 FIRE PROTECTION IMPAIRMENT CONTROL 23 AP 10-103 FIRE PROTECTION IMPAIRMENT CONTROL 24 AP 10-103 FIRE PROTECTION IMPAIRMENT CONTROL 25 AP 15C-004 PREPARATION, REVIEW AND APPROVAL OF PROCEDURES, INSTRUCTIONS AND FORMS 40A EDMG-T01 EDMG TOOL BOX 8

EMG C-0 LOSS OF ALL AC POWER 22 EMG C-0 LOSS OF ALL AC POWER 23 EMG E-0 REACTOR TRIP OR SAFETY INJECTION 27 EMG ES-02 REACTOR TRIP RESPONSE 25 EMG ES-04 NATURAL CIRCULATION COOLDOWN 14B EPP 06-005 EMERGENCY CLASSIFICATION 4B MGE TP-005 TEMPORARY POWER FOR PA02 SUPPLIED LOADS 10 OFN KC-016 FIRE RESPONSE 32A OFN NB-030 LOSS OF AC EMERGENCY BUS NB01 (NB02) 27 RNM C-0534 GENERATOR FIELD DIRECT CURRENT RELAY TYPE DGF 3

A1-7 Number Title Revision STN FC-002 AUX FEEDWATER TURBINE OVERSPEED TEST 05/23/2011 STN PE-040G TRANSIENT EVENT WALKDOWN 4

STN PE-049E TRANSIENT EVENT ESSENTIAL SERVICE WATER SYSTEM INSPECTION 1

STS AL-103 TURBINE-DRIVEN AFW PUMP INSERVICE PUMP TEST 12/07/2011 STS CR-001, Att. A pg 57 SHIFT LOG FOR MODES 1, 2, & 3 77C STS NB-005 BREAKER ALIGNMENT VERIFICATION 22 SYS AL-120 DRIVEN OR TURBINE-DRIVEN AFW PUMP OPERATIONS 41 SYS CC-320 GENERATOR HYDROGEN AND CARBON DIOXIDE SYSTEM PURGING TO AIR 27 SYS CC-321 GENERATOR HYDROGEN EMERGENCY DEPRESSURIZATION 1

SYS FP-290 TEMPORARY FIRE PUMP OPERATIONS 10 SYS FP-290 TEMPORARY FIRE PUMP OPERATIONS 11 SYS FP-290 TEMPORARY FIRE PUMP OPERATIONS 12 SYS FP-290 TEMPORARY FIRE PUMP OPERATIONS 13 SYS FP-290 TEMPORARY FIRE PUMP OPERATIONS 14 SYS NB-320 DEENERGIZING AND ENERGIZING ESF TRANSFORMERS 8

TMP 12-007 PLACING PA BUSES ON STARTUP XFMR WITH 345-60 BREAKER UNAVAILABLE 0

CALCULATIONS Number Title Revision XX-E-006 AC SYSTEM ANALYSIS DESIGN BASIS DOCUMENTS (DBD)

Number Title Revision FSAR Ch 15 ACCIDENT ANALYSIS 11

A1-8 SYSTEM HEALTH REPORTS Number Title Revision AUXILIARY FEEDWATER 10/1/2011 -

12/31/2011 ESSENTIAL SERVICE WATER 10/1/2011 -

12/31/2011 MISCELLANEOUS DOCUMENTS Number Title Revision/Date 013690 CHANGE PACKAGE FOR CT WIRING JUNCTION BLOCK XMR01 1

UIN 012ADC8 ALS TRIBOLOGY DIESEL ENGINE UNIT NO. FP-D1FP001B OIL SAMPLE LAB RESULTS (FOR THE PERIODS SEPTEMBER 21, 2006 TO MARCH 19, 2009)

UIN 012ADC8 ALS TRIBOLOGY DIESEL ENGINE UNIT NO. FP-D1FP001B OIL SAMPLE LAB RESULTS (FOR THE PERIODS MARCH 25, 2010 TO JULY 23, 2011)

UIN 012ADC5 ALS TRIBOLOGY GEARBOX UNIT NO. FP-D1FP001B OIL SAMPLE LAB RESULTS (FOR THE PERIODS JUNE 15, 2006 TO JUNE 8, 2009)

UIN 012ADC5 ALS TRIBOLOGY GEARBOX UNIT NO. FP-D1FP001B OIL SAMPLE LAB RESULTS (FOR THE PERIODS JANUARY 11,2010 TO SEPTEMBER 15, 2011)

WCNOC ULTRASONIC THICKNESS REPORT WP# 12-350393-005 01/15/2012 TR-92-0063 W01 INDIVIDUAL PLANT EXAMINATION REPORT 09/1992 IIT 10-01 INVESTIGATION INTO THE MATERIAL CONDITION OF ESW PIPING AND EVENTS FROM CR 00026466 AND CR 00028474 0

CONTROL ROOM LOGS 01/13/2012 -

02/04/2012 PMO PROJECT STATUS 01/27/2012

A1-9 Number Title Revision/Date SEQUENCE OF EVENTS LOG 01/13/2012 13837 CHANGE PACKAGE: GENERATOR CO2 AND HYDROGEN PIPE ROUTE 0, 1 CR-001 through 004 WOLF CREEK GENERATING STATION EMERGENCY NOTIFICATION 01/13/2012 EN 47590 EVENT NOTIFICATION WOLF CREEK LOSS OF OFFSITE POWER 01/13/2012 WCAP-16423-NP PRESSURIZED WATER REACTOR OWNERS GROUP STANDARD PROCESS AND METHODS FOR CALCULATING RCS LEAKRATE FOR PRESSURIZED WATER REACTORS 0

STS RE-004, Performed 1/13/12 @

1511 SHUTDOWN MARGIN DETERMINATION 04A STS RE-004, Performed 1/13/12 @

1817 SHUTDOWN MARGIN DETERMINATION 04A ES-0.2 Background, HES02BG WOG BACKGROUND FOR EMERGENCY PROCEDURES 2

Foldout WOG BACKGROUND FOR EMERGENCY PROCEDURES 2

VENDOR MANUALS Number Title DATE I.L. 41-747G WESTINGHOUSE TYPE DGF GENERATOR FIELD RELAY 02/1977 M-021-00086 W40 INSTRUCTION MANUAL FOR TURBINE TERRY CORP.

11/09/2010 TERRY TURBINE MAINTENANCE GUIDE, AFW APPLICATION 11/2002 DESIGN CHANGE NOTIFICATIONS (DCN)

A1-10 Number Title Revision NO NUMBER DIESEL FIRE PUMP REPLACEMENT 0

DRR 11-2344-P01 EMG E-0 REACTOR TRIP OR SAFETY INJECTION 27 ENGINEERING REPORTS (ER)

Number Title Revision WO 11-339015-004 N31 LOSS OF CAVITY COOLING ON 3/19/2011 0

WO 12-350418-005 N31 LOSS OF CAVITY COOLING ON 1/13/2012 0

CR

00039533, SWO 11-341977 INTERIM OPERATION WITH A DEGRADED SOURCE RANGE DETECTOR, SENI0031 0

TEMPORARY MODIFICATION ORDER Number Title Revision 12-008-FP 1FP001PB - DIESEL-DRIVEN FIRE PUMP (INSTALLATION OF A TEMPORARY DIESEL FIRE PUMP) 0 11-009-KH-0 TEMPORARY MODIFICATION FOR CO2 TRUCK FILL CONNECTION 0

12-002-XX-0 TEMP POWER ACCESS FOR CHEM HOT LAB EQUIP 0

12-003-KJ TEMP POWER FOR PG019 AND PG020, AND XNB01 CONTROL CIRCUIT 0, 1 12-004-PG-1 LOAD CENTER PG13 0, 1 WORK ORDERS (WO) 09-320434-003 09-322358-000 11-340360-006 11-342312-000 11-342312-001 11-342625-000 11-342625-001 11-343739-000 11-343739-001 11-344786-000

A1-11 11-345429-008 11-346720-000 11-346762-017 12-350382-000 12-350382-001 12-350382-002 12-350382-004 12-350382-006 12-350382-014 12-350382-015 12-350382-016 12-350382-017 12-350382-018 12-350382-019 12-350382-020 12-350382-021 12-350382-022 12-350387-000 12-350387-001 12-350387-002 12-350387-003 12-350391-001 12-350395-000 12-350396-000 12-350396-001 12-350398-000 12-350416-000 12-350427-000 12-350443-002 12-350443-003 12-350443-004 12-350443-006 12-350443-010 12-350443-012 12-350470-000 12-350471-000 12-350479-000 12-350604-000 12-350646-000 12-350656-000 12-350657-000 12-350869-000 12-350898-000 12-350937-000 12-350937-001 CONDITION REPORTS (CR) 25834 26466 28474 35122 37200 39512 39909 39910 40282 43710 47543 47552 47647 47648 47653 47654 47656 47658 47660 47661 47665 47666 47667 47670 47674 47678 47700 47708 47722 47724 47727 47728 47729 47735 47736 47738 47739 47741 47752 47752 47758 47760 47774 47778 47787 47834 47848 47849 47881 47884 47886 47893 47917 47926 47932 47940 47942 47965 47976 48021 48025 48026 48033 48036 48046 48049 48083 48103 48104 48133 48155 48172 48320 48368 48369 48372 48375 48422 48466 48512 48517 48527 48534*

48574*

48624*

48643 48677*

48687*

48693 48764 2006-102

CRs issued as a result of inspection activities.

A2-1 SEQUENCE OF EVENTS Wolf Creek Nuclear Operating Company Date/Time Event Description January 13, 2012 The plant is at one hundred percent rated thermal power, with no plant evolutions in progress, transmission switching, or adverse weather conditions; pressurizer power operated relief valve PCV-455A block valve is closed due to leakby on PCV-455A.

14:02:54.707 Main generator output breaker 345-60 C phase develops a fault 14:02:54.740 Wolf Creek 345 kV east bus differential sensed 14:02:54.755 Wolf Creek main generator transformer lockout 14:02:54.757 East bus 345-120 breaker opens 14:02:54.758 East bus 345-90 breaker opens 14:02:54.759 Main generator output breaker 345-60 C phase failure (most likely failure is foreign material by process of elimination); east bus 345-60 breaker opens.

345 kV east bus is deenergized as a result of breakers 345-60, 345-90, and 345-120 opening.

14:02:54.767 Unit trip signal, turbine trips 14:02:54.768 Main generator output breaker 345-50 breaker opens 14:02:54.769 13-48 transformer No. 7 opens, removing power to safety-related train A 4160 Vac bus 14:02:54.787 Main generator protective relay trip, main generator trips 14:02:54.816 Fast bus transfer of nonvital buses from unit auxiliary transformer to startup transformer begins, PA0211 breaker opens 14:02:54.823 PA0101 breaker opens 14:02:54.833 PA0202 breaker closes 14:02:54.841 PA0110 breaker closes, this completes the fast transfer 14:02:54.919 Startup transformer protective relay trips on B phase differential 14:02:54.930 Wolf Creek 345 kV west bus differential lockout 14:02:54.932 West bus 345-40 breaker opens

A2-2 14:02:54.933 West bus 345-110 breaker opens 14:02:54.934 West bus 345-70 breaker opens; the 345 kV west bus is deenergized as a result of breakers 345-40, 345-70, and 345-110 opening.

Loss of offsite power; the 345 kV east and west buses are deenergized.

14:02:54.972 PA0202 breaker opens 14:02:54.975 PA0110 breaker opens 14:02:54.979 PA0201 breaker opens, removing power to safety-related train B 4160 Vac bus 14:02:54.994 Reactor main trip breaker B opens.

Reactor trips due to turbine trip and reactor power greater than 50 percent.

14:02:55.006 Reactor main trip breaker A opens.

The plant is in Mode 3 14:02:55.984 NB0112 breaker opens, disconnecting power from offsite to the safety-related train A 4160 Vac bus 14:02:56.102 NB0209 breaker opens, disconnecting power from offsite to the safety-related train B 4160 Vac bus 14:02:57 Instrument air pressure starts to decrease due to loss of power to the air compressors.

Letdown isolates due to loss of power.

14:02:59.241 Steam generator A atmospheric vent valve opens 14:03 Motor-driven fire pump and the jockey fire pump are without power as a result of the LOOP.

Temporary diesel-driven fire pump is drained to prevent freezing and does not start automatically on loss of power (normal diesel-driven fire pump would have started automatically).

14:03:01.006 Loop 2 supply valve to turbine-driven AFW opens 14:03:01.079 Steam generator D atmospheric vent valve opens 14:03:01.295 Loop 3 supply valve to turbine-driven AFW opens 14:03:01.482 Steam generator C atmospheric vent valve opens 14:03:02.656 Emergency diesel generator B is running; output breaker NB0211 closes, reenergizing the train B safety-related 4160 Vac bus.

14:03:02.953 Emergency diesel generator A is running; output breaker NB0111 closes, reenergizing the train A safety-related 4160 Vac

A2-3 bus.

14:03:02.973 Steam generator B atmospheric vent valve opens 14:03:04.390 Steam dump valve group 1 opens 14:03:04.442 Steam dump valve group 3 opens 14:03:04.546 Steam dump valve group 4 opens 14:03:04.629 Steam dump valve group 2 opens 14:03:05.886 Steam dump valve group 3 closes 14:03:05.965 Steam dump valve group 4 closes 14:03:06.260 Steam dump valve group 2 closes 14:03:07.116 Steam dump valve group 1 closes 14:03:46.853 Steam generator B atmospheric vent valve closes 14:04:08.239 Steam generator D atmospheric vent valve closes 14:04:08.518 Steam generator C atmospheric vent valve closes 14:04:28.149 Steam generator A atmospheric vent valve closes 14:08:06 Charging flow starts to increase due to loss of instrument air to containment 14:09:28.467 Main steam isolation valve loop 4 closes 14:09:28.491 Main steam isolation valve loop 2 closes 14:09:28.569 Main steam isolation valve loop 1 closes 14:09:28.581 Main steam isolation valve loop 3 closes 14:10:19.739 Instrument air to containment isolation valve is closed 14:12 Commenced EMG ES-02, Reactor Trip Response 14:13 Completed EMG E-0, Reactor Trip or Safety Injection 14:13:55 Charging flow reaches maximum rate as a result of loss of instrument air to containment.

With no letdown and maximum charging, the pressurizer begins to fill and reactor coolant system pressure starts to increase.

14:15 Notification of Unusual Event is declared for EAL-6 due to a LOOP expected to last longer than 15 minutes 14:16 Source range nuclear instruments have energized 14:19:31 Pressurizer power operated relief valve PCV-456A lifts 14:19:32 Pressurizer power operated relief valve PCV-456A reseats

A2-4 14:20:39 Pressurizer power operated relief valve PCV-456A lifts 14:20:40 Pressurizer power operated relief valve PCV-456A reseats 14:21:30 Pressurizer power operated relief valve PCV-456A lifts 14:21:32 Pressurizer power operated relief valve PCV-456A reseats 14:22:15 Pressurizer power operated relief valve PCV-456A lifts 14:22:16 Pressurizer power operated relief valve PCV-456A reseats 14:22:50 Pressurizer power operated relief valve PCV-456A lifts 14:22:51 Pressurizer power operated relief valve PCV-456A reseats 14:23:20 Pressurizer power operated relief valve PCV-456A lifts 14:23:21 Pressurizer power operated relief valve PCV-456A reseats 14:23:47 Pressurizer power operated relief valve PCV-456A lifts 14:23:48 Pressurizer power operated relief valve PCV-456A reseats 14:24:14 Pressurizer power operated relief valve PCV-456A lifts 14:24:15 Pressurizer power operated relief valve PCV-456A reseats 14:24:41 Pressurizer power operated relief valve PCV-456A lifts 14:24:42 Pressurizer power operated relief valve PCV-456A reseats 14:25:08 Pressurizer power operated relief valve PCV-456A lifts 14:25:09 Pressurizer power operated relief valve PCV-456A reseats 14:25:33 Pressurizer power operated relief valve PCV-456A lifts 14:25:34 Pressurizer power operated relief valve PCV-456A reseats 14:25:58 Pressurizer power operated relief valve PCV-456A lifts 14:25:59 Pressurizer power operated relief valve PCV-456A reseats 14:26:23 Pressurizer power operated relief valve PCV-456A lifts 14:26:24 Pressurizer power operated relief valve PCV-456A reseats 14:26:48 Pressurizer power operated relief valve PCV-456A lifts 14:26:49 Pressurizer power operated relief valve PCV-456A reseats 14:27:13 Pressurizer power operated relief valve PCV-456A lifts 14:27:14 Pressurizer power operated relief valve PCV-456A reseats 14:27:38 Pressurizer power operated relief valve PCV-456A lifts 14:27:39 Pressurizer power operated relief valve PCV-456A reseats

A2-5 14:28:05 Instrument air compressors are restarted; instrument air pressure returning to normal.

Charging flow is returning to normal.

14:28:57 Pressurizer power operated relief valve PCV-456A lifts 14:28:58 Pressurizer power operated relief valve PCV-456A reseats 14:29:45 Pressurizer power operated relief valve PCV-456A lifts 14:29:47 Pressurizer power operated relief valve PCV-456A reseats 14:30:49 Pressurizer power operated relief valve PCV-456A lifts 14:30:50 Pressurizer power operated relief valve PCV-456A reseats 14:32:06 Pressurizer power operated relief valve PCV-456A lifts 14:32:08 Pressurizer power operated relief valve PCV-456A reseats 14:32:47 Pressurizer power operated relief valve PCV-456A lifts 14:32:48 Pressurizer power operated relief valve PCV-456A reseats 14:33:25 Pressurizer power operated relief valve PCV-456A lifts 14:33:26 Pressurizer power operated relief valve PCV-456A reseats 14:34:32 Pressurizer power operated relief valve PCV-456A lifts 14:34:33 Pressurizer power operated relief valve PCV-456A reseats 14:35:54 Letdown restored to service; reactor coolant system pressure is maintained below pressurizer power operated relief valve setpoint for remainder of event.

14:37 Site watch reported breaker 345-60 has visible damage 14:47 Fire protection informed to commence fire impairments for LOOP 15:00 Fire protection discussed with control room that the station did not have fire water system available.

Reestablishing fire water was not a priority for operations at this time.

15:01 Natural circulation flow verified per EMG ES-02, Reactor Trip Response, Attachment A 15:02 One hour continuous fire watch compensatory measures were not established for loss-of-fire water 15:30 Restored spent fuel pool cooling 15:50 Completed EMG ES-02, Reactor Trip Response 15:51 Commenced EMG ES-04, Natural Circulation Cooldown

A2-6 16:45 Senior reactor operator reviewing post-trip review trends identifies a possible water leak inside containment; suspect essential service water based on containment parameters.

345 kV east bus reenergized from La Cygne line by closing breaker 345-120. The air disconnects for breaker 345-60 were opened first.

16:56 Shift manger directed the site watch to rack out the motor-driven fire pump breaker.

Site watch made several attempts to prime and start the temporary diesel-driven fire pump.

17:00 Closed breaker 13-48 for transformer No. 7 to energize train A safety-related 4160 Vac from offsite source 17:09 Wolf Creek exited the Notification of Unusual Event because one source of offsite power had been restored.

17:14 Source range nuclear instrument NI-31 indication began trending up; known issue from loss-of-cavity cooling that is undergoing troubleshooting.

17:21 Emergency diesel generator A secured 17:30 Fire protection and engineering provide initial coverage for continuous fire watch areas deemed to be the most important; however, they are not qualified to stand fire watch.

17:36 Commenced reactor coolant system cooldown per EMG ES-04, Natural Circulation Cooldown 17:37 After entering containment, personnel identified essential service water leak on the C containment cooler (~5 gpm) 17:46 Essential service water leak on the C containment cooler is isolated 18:00 Temporary diesel-driven fire pump start did not work due to drain valve left open 19:02 Authorized emergency temporary modification to cut 3-inch hole in control building to provide temporary power to chemistry hot lab to perform reactor coolant sampling 19:28 Commenced startup transformer B phase differential testing 20:00 Emergency hydrogen purge of the main generator started.

Qualified fire watch reliefs were obtained.

21:00 Emergency hydrogen purge of the main generator secured 21:40 345 kV west bus reenergized by closing breaker 345-40 21:42 Temporary modification to provide temporary power to chemistry

A2-7 hot lab is complete 21:51 Temporary diesel-driven fire pump was primed using the fire truck taking a suction from the lake and is now running 22:07 Chemistry lab has power and analyzes reactor coolant system boron concentration of 1716 ppm, greater than the required shutdown value 23:10 Temporary diesel-driven fire pump supplying fire protection header January 14, 2012 00:00 Source range nuclear instrument NI-31 indication began trending down as a result of reactor coolant system cooldown 01:12 Plant enters Mode 4 02:44 Turbine-driven AFW pump tripped on overspeed while securing the pump 03:08 Residual heat removal pump B placed in service for shutdown cooling 04:55 Completed purging the main generator with CO2 07:50 Plant enters Mode 5 11:26 Essential service water leak on C containment cooler determined to be through-wall leak on the main header 12:36 Control room received emergency diesel generator B trouble alarm; local operator reports a generator field ground alarm.

Emergency diesel generator B readings are all stable.

13:32 Authorized emergency temporary modification to power the emergency diesel generator starting air compressors, the auxiliary building sump pumps, and transformer auxiliaries 13:37 Reactor coolant system cooldown has been completed, cooldown secured.

14:34 Residual heat removal pump A aligned for shutdown cooling 20:14 Residual heat removal pump A placed in service for shutdown cooling 20:46 Secured residual heat removal pump B 22:48 Temporary power has been installed for the emergency diesel generator starting air compressors, the auxiliary building sump pumps, and transformer auxiliaries

A2-8 January 15, 2012 02:35 Emergency diesel generator starting air reservoirs are at normal pressure, auxiliary building sump pumps are running lowering sump level slowly, and transformer auxiliaries have power 04:40 Auxiliary building sump pumps are not lowering level 06:11 Closed the alternate feeder breaker NB0212 to power train B from train A once in Mode 5 06:21 Opened the emergency diesel generator B output breaker NB0211 06:26 Emergency diesel generator B secured 15:35 Troubleshooting activities on emergency diesel generator B identified a ground on the generator field 15:54 Auxiliary building sump pumps were determined to be wired backwards during the emergency temporary power modification January 16, 2012 16:00 Completed EMG ES-04, Natural Circulation Cooldown 17:00 Temporary diesel-driven fire pump was secured to check engine oil and reconnect a buoy to a suction hose.

Fire truck was used to maintain pressure on fire protection pressure.

17:30 Fire truck lost prime and resulted in loss-of-fire protection pressure 18:00 Temporary diesel-driven fire pump was restarted and fire protection pressure was restored January 17, 2012 21:00 Commenced back-feeding offsite power through the main and unit auxiliary transformers to power the non-safety-related buses (air links for main generator opened, breakers PA0101 and PA0211 closed)

January 19, 2012 00:51 Motor-driven fire pump was started to test the breaker that had been racked out

A2-9 05:00 Temporary diesel-driven fire pump was secured 05:45 It was determined that the running motor-driven fire pump had caused the temporary diesel-driven fire pump to dead-head due to the location of the recirculation line and the discharge check valve; temporary diesel-driven fire pump is unavailable.

January 21, 2012 18:00 Temporary diesel-driven fire pump repaired, discharge check valve relocated to prevent future damage, two priming pumps replaced, main pump was replaced January 23, 2012 18:00 Successfully completed performance testing of the temporary diesel-driven fire pump, declared functional and has remained in continuous operation February 3, 2012 11:56 345 kV west bus deenergized by opening breakers 345-40, 345-70, and 345-110 to support closing the air break to the startup transformer for no-load testing 12:07 Energized the 345 kVac west bus and the startup transformer by closing breaker 345-70 12:28 Closed breakers 345-110 and 345-40 13:50 Energized PA01 from startup transformer by closing breaker PA0110 14:05 Energized PA02 from startup transformer by closing breaker PA0202 17:09 Energized train B safety-related 4160 Vac from the startup transformer by closing breaker PA0201 19:08 Emergency diesel generator B started for ground testing 19:33 Emergency diesel generator B at full load 19:46 Startup transformer testing is complete, startup transformer returned to service 19:54 Startup transformer stress cones have been reworked 23:52 Cables associated with the startup transformer have been replaced

A2-10 23:53 Emergency diesel generator B field ground alarm in February 4, 2012 00:09 Emergency diesel generator B ground detection relay replaced 01:08 Emergency diesel generator B secured 05:26 Startup transformer to safety-related train B bus damaged wires replaced to return breaker PA0201 to service 05:32 Startup transformer to PA01 bus potential transformer PT-113-1 replaced to return breaker PA0110 to service 11:02 Emergency diesel generator B started for ground testing 11:28 Emergency diesel generator B output breaker NB0211 is closed 11:42 Emergency diesel generator B at full load 11:45 Emergency diesel generator B field ground alarm in 12:24 Emergency diesel generator B secured, next restart will be when the vendor arrives onsite to assist ground testing February 13, 2012 20:08 Attempted to start reactor coolant pump A.

Startup transformer protective relay trips on B phase differential; breakers PA0110, PA0201, and PA0202 open.

Loss of 4160 Vac safety-related train B equipment.

20:56 4160 Vac safety-related buses are cross tied, train B equipment power restored

A3-1 January 27, 2012 MEMORANDUM TO:

Mark Haire, Chief, Operations Branch Division of Reactor Safety FROM:

Elmo E. Collins, Regional Administrator /RA AHowell for/

Region IV

SUBJECT:

AUGMENTED INSPECTION TEAM CHARTER TO EVALUATE THE LOSS OF OFFSITE POWER EVENT AT WOLF CREEK GENERATING STATION You have been selected to lead an Augmented Inspection Team (AIT) to assess the circumstances surrounding the complete loss of offsite power and reactor trip event that resulted in the declaration of a Notification of Unusual Event (NOUE) on January 13, 2012. The following are the other team members.

Mike Runyan (Region IV)

John Dixon (Region IV)

Brian Correll (Region IV)

John Watkins (Region IV)

Gurcharan Matharu (NRR)

Jesse Robles (NRR)

A.

Basis On January 13, 2012, Wolf Creek Generating Station declared a Notification of Unusual Event (NOUE) at 2:15 p.m. CST following an automatic reactor trip and loss of offsite power that occurred at 2:03 p.m. CST. The failure of a main generator output breaker, followed by an unexplained loss of power to the startup transformer, caused the switchyard to be deenergized, which removed the plants connection to the power grid.

All safety systems initially responded as expected, and emergency diesel generators automatically powered safety-related equipment.

At 5:09 p.m. on January 13, Wolf Creek terminated the NOUE after offsite power was partially restored. Plant personnel are continuing to investigate the cause of the failure and determine necessary repairs. The plant is in a safe condition and has been brought to the cold shutdown operating mode, with offsite power supplying safety-related loads and select non-vital loads and the emergency diesel generators secured. The licensee restored power to most of the plant systems on January 17 after verifying that the UNITED STATES NUCLEAR REGULATORY COMMISSION REGION IV 1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511

A3-2 non-vital switchboards were safe to energize. There were no radiological releases due to this event.

In accordance with Management Directive 8.3, NRC Incident Investigation Program, deterministic and conditional risk criteria were used to evaluate the level of NRC response for this operational event. This event met deterministic criteria for multiple failures in systems used to mitigate the event, and repetitive failures or events involving safety-related systems. The initial risk assessment, while subject to some uncertainties, indicates that the conditional core damage probability for the event is in the overlap range for a special inspection/augmented inspection. Region IV, in consultation with the Office of Nuclear Reactor Regulation (NRR), concluded that the NRC response should be an AIT.

This augmented inspection is chartered to identify the circumstances surrounding this event, review the licensees actions following discovery of the conditions, and evaluate the responses of plant equipment and the licensee to the event.

B.

Scope The augmented inspection team is to perform data gathering and fact finding in order to address the following:

1.

Develop an event chronology of significant events during the loss of offsite power and the trip, the subsequent cooldown, recovery efforts, and troubleshooting/cause analysis. This should include identifying the conditions preceding the event, system responses, and equipment performance. Assess and document the available information on the probable cause of the loss of offsite power.

2.

Assess licensee actions taken in response to the event, actions to cool the plant down, and actions performed during recovery of plant systems, other operator actions, and event classification and reporting.

3.

Assess procedure use and adequacy for this event.

4.

Assess whether plant systems responded as expected. Compare the actual plant response to the applicable safety analyses.

5.

Assess whether the turbine-driven auxiliary feedwater pump was operated in accordance with station procedures and the vendors recommendations. Assess the licensees efforts to identify the cause of the unexpected overspeed trip alarm while operators were shutting down the pump.

6.

Assess the licensees efforts to identify the source of the ground on emergency diesel generator (EDG) B. Evaluate whether the cause of the ground would have impacted the ability of the EDG to perform reliably through its design mission time.

7.

Determine whether the loss of power and subsequent restarting of the essential service water pumps resulted in an abnormal system pressure transient. Assess the licensees corrective action adequacy and timeliness in correcting this known design

A3-3 problem. Use test records to identify which sections of essential service water piping have been subject to recent non-destructive examination to identify pitting that does not meet minimum wall thickness requirements, and which sections have not.

Compare this result to the licensees corrective action documentation to identify whether there are areas that were missed or not correctly reported. Assess the licensees overall plan and schedule for piping inspections to determine whether this has been timely and whether they adequately considered the safety significance.

8.

Assess the impact of the deviation between source range nuclear instrument channels on operator decision-making and the ability to verify adequate shutdown margin existed. Assess the appropriateness and timeliness of the licensees cause assessment and corrective action for this condition.

9.

Assess the cause of the initial diesel-driven fire pump failure. Evaluate the adequacy of the temporary modification to be able to meet the design and licensing basis requirements for the system. Evaluate the adequacy of the actual installation and operating procedures, including suction source, weather protection, minimum flow design, and ability to maintain system pressure during a prolonged loss of power.

Identify the sequence of events that led to subsequent pump failure when the motor-driven fire pump was returned to service.

10.

Assess whether past maintenance-related activities could have contributed to the event, or impacted the response and recovery.

11.

Assess the impact of the prolonged loss of offsite power to non-safety-related equipment on: the initial event response and ability of safety-related equipment to continue to function through their full design mission times; the timing and capability to cool the plant down to Mode 5, including being able to take required chemistry samples; and the capability to implement the site emergency plan

12.

Collect data to support an independent assessment of the risk significance of the event.

13.

Assess the results of the charter items above to determine whether there were issues with quality assurance, radiological controls, security or safeguards, or safety culture components.

C.

Guidance The team will begin in-office inspection the week of January 23, 2012, and report to the site and conduct an entrance meeting on January 30, 2012. Inspection Procedure 93800, AAugmented Team Inspection provides additional guidance to be used during the conduct of the inspection. Your duties will be as described in this procedure and should emphasize fact-finding in the review of the circumstances surrounding the event.

It is not the responsibility of the team to examine the regulatory process. The team should notify Region IV management of any potential generic issues identified related to

A3-4 this event for discussion with NRR. Safety or security concerns identified that are not directly related to the event should be reported to the Region IV office for appropriate action.

It is anticipated that the on-site portion of the inspection will be completed by February 9, 2012. You should provide a recommendation concerning when the onsite inspection should be concluded after you are on site.

An initial briefing of Region IV management will be provided on Tuesday, January 31, 2012, with daily briefings thereafter. In accordance with IP 93800, you should promptly recommend a change in inspection scope or escalation if information indicates that the assumptions used in the MD 8.3 risk analysis were incorrect.

A report documenting the results of the inspection should be issued within 30 days of the completion of the inspection. The report should address all applicable areas specified in Section 03.02 of Inspection Procedure 93800. At the completion of the inspection, you should provide recommendations for improving the Reactor Oversight Process baseline inspection procedures and Augmented Inspection process based on any lessons learned, as well as recommendations for generic communications.

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555*0001 March 15, 2013 Mr. Matthew W. Sunseri President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation Post Office Box 411 Burlington, KS 66839

SUBJECT:

WOLF CREEK GENERATING STATION - PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF JANUARY 2012 LOSS OF OFFSITE POWER EVENT (TAC NO. MF0995)

Dear Mr. Sunseri:

Enclosed for peer review is the preliminary Accident Sequence Precursor analysis of the loss of offsite power event which occurred at the Wolf Creek Generating Station on January 13, 2012.

Wolf Creek Nuclear Operating Corporation reported the event in Licensee Event Report No. 482/12-001, dated April 9,2012, and the U.S. Nuclear Regulatory Commission staff documented its review and evaluation in Inspection Report Nos. 50-482/12-08, 12-09, and 12-10, dated April 4, August 6, and September 21,2012, respectively.

Since the analysis is preliminary, it is not available to the public. Please provide any comments you may have to me by April 22, 2013. If you have any questions, please contact me at 301-415-2296 or via e-mail at fred.lyon@nrc.gov.

Sincerely, Carl F. Lyon, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-482 Enclosure As stated cc wlo encl: Distribution via Listserv

March 15,2013 Mr. Matthew W. Sunseri President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation Post Office Box 411 Burlington, KS 66839

SUBJECT:

WOLF CREEK GENERATING STATION - PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF JANUARY 2012 LOSS OF OFFSITE POWER EVENT (TAC NO. MF0995)

Dear Mr. Sunseri:

Enclosed for peer review is the preliminary Accident Sequence Precursor analysis of the loss of offsite power event which occurred at the Wolf Creek Generating Station on January 13,2012.

Wolf Creek Nuclear Operating Corporation reported the event in Licensee Event Report No. 482/12-001, dated April 9, 2012, and the U.S. Nuclear Regulatory Commission staff documented its review and evaluation in Inspection Report Nos. 50-482/12-08, 12-09, and 12-10, dated April 4, August 6, and September 21,2012, respectively.

Since the analysis is preliminary, it is not available to the public. Please provide any comments you may have to me by April 22, 2013. If you have any questions, please contact me at 301-415-2296 orvia e-mail atfred.lyon@nrc.gov.

Sincerely, IRA!

Carl F. Lyon, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-482 Enclosure As stated cc wlo encl: Distribution via Listserv DISTRIBUTION: YT020130045 PUBLIC (cover letter)

RidsNrrDorlLpl4 Resource RidsResOd Resource NON-PUBLIC (enclosure)

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memo dated OFFICE NRRlDORULPL4/PM NRR/DORULPL4/LA RES/DRAID NRRlDORULPL4/BC NRRlDORULPL4/PM NAME FLyon JBurkhardt DCoe*

MMarkley (CFLyon for)

FLyon (BSingal for)

DATE 3/15/13 3/15/13 2/22/13 3/15/13 3/15/13 OFFICIAL RECORD COpy

August 16, 2012 MEMORANDUM TO:

Harold Chernoff, Chief Operating Experience Branch Division of Inspection and Regional Support Office of Nuclear Reactor Regulation FROM:

John McHale, Chief /RA/

Operator Licensing and Training Branch Division of Inspection and Regional Support Office of Nuclear Reactor Regulation

SUBJECT:

EVALUATION OF ISSUE FOR RESOLUTION 2012-04 RELATING TO WOLF CREEKLOSS OF OFFSITE POWER AND NOTIFICATION OF UNUSUAL EVENT The Operator Licensing and Training Branch (IOLB) has reviewed Issue for Resolution (IFR) 2012-04 relating to Wolf CreekLoss of Offsite Power (LOOP) and Notification of Unusual Event (NOUE). The IOLBs evaluation focused on operator performance during the event, and whether their performance was negatively affected by the quality of plant procedures, the quality of operator training, and the ability of the control room simulator (as used in training) to accurately model the actual plant. Enclosed is our evaluation. This completes our review and evaluation efforts associated with TAC No. ME8004.

Enclosure:

As stated CONTACT:

David Muller, NRR/DIRS/IOLB (301)415-1412

MEMORANDUM TO:

Harold Chernoff, Chief Operating Experience Branch Division of Inspection and Regional Support Office of Nuclear Reactor Regulation FROM:

John McHale, Chief /RA/

Operator Licensing and Training Branch Division of Inspection and Regional Support Office of Nuclear Reactor Regulation

SUBJECT:

EVALUATION OF ISSUE FOR RESOLUTION 2012-04 RELATING TO WOLF CREEKLOSS OF OFFSITE POWER AND NOTIFICATION OF UNUSUAL EVENT The Operator Licensing and Training Branch (IOLB) has reviewed Issue for Resolution (IFR) 2012-04 relating to Wolf CreekLoss of Offsite Power (LOOP) and Notification of Unusual Event (NOUE). The IOLBs evaluation focused on operator performance during the event, and whether their performance was negatively affected by the quality of plant procedures, the quality of operator training, and the ability of the control room simulator (as used in training) to accurately model the actual plant. Enclosed is our evaluation. This completes our review and evaluation efforts associated with TAC No. ME8004.

Enclosure:

As stated CONTACT:

David Muller, NRR/DIRS/IOLB (301)415-1412 cc:

JRobles, NRR/DIRS/IOEB ADAMS ACCESSION NO.: ML122260214 OFFICE NRR/DIRS/IOLB NRR/DIRS/BC: IOLB NAME D. Muller J. McHale DATE 8/16/2012 8/16/2012 OFFICIAL RECORD COPY

ENCLOSURE EVALUATION OF ISSUE FOR RESOLUTION (IFR) 2012-04:

WOLF CREEKLOSS OF OFFSITE POWER (LOOP) AND NOTIFICATION OF UNUSUAL EVENT (NOUE) 1.0 Purpose of Evaluation The purpose of this evaluation was to review a recent operating event which occurred at the Wolf Creek Generating Station and provide recommendations for any generic communications or regulatory actions. On January 13, 2012, Wolf Creek declared a NOUE following a LOOP and automatic reactor trip. The Operator Licensing and Training Branchs (IOLB) evaluation focused on operator performance during the event, and whether their performance was negatively affected by the quality of plant procedures, the quality of their training, and the ability of the control room simulator (as used in training) to accurately model the actual plant.

2.0 Brief Description of the Event On January 13, 2012, with the Wolf Creek Generating Station, Unit 1, operating at 100 percent power, a LOOP and automatic reactor trip occurred. The LOOP was the result of two equipment failures: (1) a fault on the main generator output breaker, and (2) a differential relay trip of the startup transformer. The LOOP lasted almost 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months before offsite power was partially restored. During the event, the A and B emergency diesel generators powered the safety buses, and all other safety systems performed their functions to support safe shutdown and cooldown of the plant. However, the event was complicated by five additional equipment malfunctions:

The turbine-driven auxiliary feedwater (AFW) pump experienced an inadvertent overspeed trip mechanism actuation while the operators were shutting down the pump.

The B emergency diesel generator developed a ground on the field circuit but continued to function normally.

The essential service water system experienced a water hammer event and a 5 gpm leak inside containment.

One source range nuclear instrument gave inaccurate readings.

Operators experienced considerable difficulty and delays in getting the temporary diesel-driven fire pump in service, so normal fire fighting water was not available for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months .

The above event is described in detail in the following documents:

Licensee Event Report (LER) No. 2012-001-00, dated March 12, 2012, at ADAMS Accession No. ML12080A215 NRC Augmented Inspection Team (AIT) Report No. 05000482/2012008, dated April 4, 2012, at ADAMS Accession No. ML12095A414

2 3.0 Operator Performance Overall, operator performance during the event was satisfactory, with two exceptions presented below. In particular, the AIT report noted that:

The operating crew promptly identified the reactor trip and LOOP, and identified important off-normal parameters and alarms in a timely manner.

The crew appropriately identified and addressed abnormal equipment alignments associated with non-safety-related equipment that could challenge personnel safety.

The operating crew performed adequately to stabilize the plant, minimize potential dangers due to the prolonged LOOP, established critical parameter limits for systems required for safe shutdown, and safely conducted a natural circulation cooldown.

The EOPs were properly implemented, including the natural circulation cooldown procedure, EMG ES-04, and the operators exhibited fundamental operator competencies when responding to the event while using EOPs.

In response to the source range nuclear instrument that gave inaccurate readings, the crew recognized the increasing counts, declared the detector inoperable, and in accordance with the Technical Requirements Manual bases document, the operating crew relied on the Gamma Metrics detectors in place of the source range detectors.

Once offsite power was restored, the crew safely completed a transition to shutdown cooling and maintained the plant in a cold shutdown condition.

The operating crew was both timely and accurate in their reporting of the NOUE to local, state, and federal entities.

Operating crew supervision exercised adequate oversight of plant status, crew performance, and site resources.

Although overall operator performance was satisfactory during the event, the AIT report did document two exceptions:

1. The operating crew did not observe/comply with a precaution stated in Procedure SYS AL120, Motor-Driven or Turbine-Driven Pump Operations. Specifically, the precaution stated that operation of the turbine-driven AFW pump at low flow rates should be minimized due to cavitation concerns. Contrary to this precaution, the turbine-driven AFW pump flow rate cycled above and below the specified low flow value for almost the entire 12.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months of pump operation, and cumulatively, the pump ran for approximately 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months at a flow rate below that stated in the precaution.

2. The operators had difficulty starting the temporary diesel-driven fire pump and keeping it running. As a result, Wolf Creek was without fire suppression water pressure for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months following the start of the event, and over the next couple of days, the licensee

3 struggled to keep the temporary diesel-driven fire pump operating and lost all fire water pressure multiple times.

4.0 Plant Procedures From the AIT report, the overall quality of plant procedures was adequate to allow the operating crew to place the plant in a safe and stable condition. The AIT report noted no procedure adequacy or quality issues with the major procedures used by the operating crew during this event, including: EMG E-0, Reactor Trip or Safety Injection, EMG ES-02, Reactor Trip Response, and EMG ES-04, Natural Circulation Cooldown. However, the AIT report did document two procedures which did have quality issues:

1. Procedure SYS AL120, Motor-Driven or Turbine-Driven Pump Operations, did not incorporate guidance in accordance with the vendors manual to secure the turbine-driven AFW pump at a minimum steam supply pressure of 77 psig. In fact, the turbine-driven AFW pump was operated below 77 psig steam supply pressure during this event for approximately one hour, and the operators did not secure the turbine-driven AFW pump until steam supply pressure was approximately 60 psig.

2. Procedure SYS FP-290, Temporary Fire Pump Operations, had at least two quality issues noted by the AIT: inadequate instructions for priming and starting the pump, and an installation drawing for the pump that was missing key components (e.g.,

suction drain valves and the discharge check valve). The quality issues with this procedure were documented by the AIT as being one of the reasons Wolf Creek was without fire water pressure during the first 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months of this event.

5.0 Operator Training From the AIT report, the overall quality of operator training was adequate to support the major actions of the crew, including crew actions to respond to the LOOP and automatic reactor trip, place the plant in a safe and stable condition, perform a natural circulation cooldown, and restore offsite power. However, the AIT report did directly document one instance of inadequate operator training, and provided one indication of a training weakness:

1. Training associated with starting and operating the temporary diesel-driven fire pump was inadequate. Operators were only given on-the-job training on operation of the temporary diesel-driven fire pump in the fall of 2011, but no lesson plan was used and some operators had only one attempt with starting the equipment. Inadequate training associated with starting and operating the temporary diesel-driven fire pump was documented by the AIT as being one of the reasons Wolf Creek was without fire water pressure during the first 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months of this event.

4

2. Contrary to a precaution stated in Procedure SYS AL120, Motor-Driven or Turbine-Driven Pump Operations, the operating crew did not minimize the time that turbine-driven AFW pump operated below the specified low flow rate. In fact, the turbine-driven AFW pump cycled above and below the specified low flow value for almost the entire 12.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months of pump operation, and cumulatively, the pump ran for approximately 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months at a flow rate below the low flow value. Although not specified as such in AIT report, this could be viewed as a weakness in operator training.

6.0 Control Room Simulator Performance There have been plant events where operator performance was negatively influenced by training received in the control room simulator due to the simulator behaving significantly different than the actual plant (negative training). For example, during an event at Millstone 3 (April 17, 2005), operators incorrectly believed a main steam safety valve was stuck open based upon negative training received on an incorrectly modeled simulator. From the AIT report, there were no indications of negative training based upon an inaccurate simulator for this event.

7.0 Conclusions and Recommendations Based upon the discussion above, the IOLB staff concluded that operator performance, plant procedures, training, and simulator performance were all adequate with regard to this event.

However, some notable exceptions were identified regarding operation of the temporary diesel-driven fire pump and the turbine-drive AFW pump. The IOLB staff recommends no generic communications or further regulatory actions, outside of the expected NRC follow-up of the unresolved items opened in the AIT report.

ENCLOSURE - PRELIMINARY INFORMATION NOT AVAILABLE TO THE PUBLIC ENCLOSURE - PRELIMINARY INFORMATION NOT AVAILABLE TO THE PUBLIC 1

Preliminary Precursor Analysis Accident Sequence Precursor Program - Office of Nuclear Regulatory Research Wolf Creek Generating Station Multiple Switchyard Faults Cause Reactor Trip and Subsequent Loss of Offsite Power Event Date: 01/13/2012 LER: 482/12-001 IRs: 50-482/12-08, 50-482/12-09, 50-482-12-10 CCDP = 5x10-4 EVENT

SUMMARY

Event Description. On January 13, 2012, at 2:02 p.m. CST, the site experienced a loss of offsite power (LOOP). The event resulted from two distinct faults. The first fault was on Phase C of the Main Generator Output Breaker 345-60. This fault resulted in the 345kV East Bus differential relay protective logic to open Breakers 345-120, 345-90, 345-60, 13-48, and 69-16, which together deenergized the East Bus. As a result of the location of the fault on Phase C of Breaker 345-60, the main generator differential relay protective logic opened Breaker 345-50. This resulted in a main generator trip signal, and started the sequence of events to shift the source of power to most station loads from the Unit Auxiliary Transformer (UAT) to the Startup Transformer (SUT) in a sequence called a fast bus transfer. The fast bus transfer resulted in Breakers PA0211 and PA0101 opening, and Breakers PA0202 and PA0110 closing. This completed the fast bus transfer and now had the station loads aligned through the SUT.

The second fault, a phase differential, occurred on Phase B of the SUT and resulted in the 345kV West Bus differential relay protective logic opening Breakers 345-40, 345-70, and 345-110, de-energizing the remaining portions of the switchyard. It also resulted in the SUT phase differential relay protective logic opening Breakers PA0110, PA0201, and PA0202. The sequence of events to this point all occurred in approximately 12 cycles (about 0.2 seconds) resulting in Wolf Creek experiencing a LOOP condition. Emergency Diesel Generators A and B automatically started and powered their respective safety buses approximately eight seconds after the start of the event. At 2:15 p.m., the shift manager declared a Notification of Unusual Event based on the expectation that the LOOP would last longer than 15 minutes. At 4:45 p.m.,

the 345kV East Bus was reenergized from the La Cygne line by closing Breaker 345-120, restoring offsite power to the Train A safety-related components (Bus NB01). At 5:09 p.m., the Notification of Unusual Event was terminated.

On January 15th, operators restored offsite power to Bus NB02 by closing the Alternate Feeder Breaker NB0212 to power Train B from Train A once in Mode 5 and EDG B was secured.

Electrical repairs were not completed until February 4th, when the SUT was returned to service and damaged wires and a bus potential transformer for Breakers PA0201 and PA0110 were replaced and the breakers were returned to service. See References 1-3 for further details.

Sequence of Key Events. The following table provides a sequence of key events:

January 13, 2012 The plant is at one hundred percent rated thermal power, with no plant evolutions in progress, transmission switching, or adverse weather

LER 482/12-001 2

conditions; pressurizer PORV Block Valve BB-8000A is closed due to PCV-455A leakage.

14:02 Main Generator Output Breaker 345-60 on Phase C develops a fault leading to a main generator transformer lockout. East Bus 345-120 Breakers 345-120, 345-90, and 345-60 open; therefore, de-energizing the 345kV East Bus. A Unit Trip Signal is received; the main turbine trips.

Main Generator Output Breaker 345-50 breaker opens and Transformer No. 7 Breaker 13-48opens, removing power to Train A Safety Bus. Fast bus transfer of non-vital buses from UAT to SUT begins, Breakers PA0211 and PA0101 open, and Breakers PA0202 and PA0110 Close completing the fast transfer. SUT protective relay trips on Phase B differential causing 345kV West Bus differential lockout. West Bus Breakers 345-40, 345-110, and 345-70 open; therefore, de-energizing the 345kV West Bus. Breakers PA0202, PA0110, PA0201 open isolating the SUT from the Train B Safety Bus. Reactor Main Trip Breaker B opens and the reactor trips due to turbine trip and reactor power greater than 50 percent. The plant is in Mode 3. Breakers NB0112 and NB0209 open, therefore, offsite power is completely disconnected from both safety buses. Instrument air pressure starts to decrease due to loss of power to the air compressors. Letdown isolates due to loss of power. SG atmospheric dump valve (ADV) A opens.

14:03 Motor-driven fire pump and the jockey fire pump are without power as a result of the LOOP. A temporary diesel-driven fire pump is drained to prevent freezing and does not start automatically on loss of power (normal diesel-driven fire pump would have started automatically).

Loops 2 and 3 supply valves to turbine-driven AFW opens. SG ADV B, C, and D open. EDGs A and B are running; Output Breakers NB0111 and NB0211 close, re-energizing both safety buses. Steam dump valves cycle open and close until the instrument air header is depleted. SG ADV B closes.

14:04 SG ADVs A, C, and D close.

14:08 Charging flow starts to increase due to loss of instrument air to containment.

14:09 Main steam isolation valves are manually closed to arrest the cooldown.

14:10 Instrument air containment isolation valve is closed.

14:12 Commenced EMG ES-02, Reactor Trip Response.

14:13 Completed EMG E-0, Reactor Trip or Safety Injection. Charging flow reaches maximum rate as a result of loss of instrument air to containment. With no letdown and maximum charging, the pressurizer begins to fill and reactor coolant system pressure starts to increase.

14:15 Notification of Unusual Event is declared due to a LOOP expected to last longer than 15 minutes.

14:16 Source range nuclear instruments have energized.

14:19 Pressurizer PORV PCV-456A begins to cycle open and closed.

LER 482/12-001 3

14:28 Instrument air compressors are restarted; instrument air pressure returning to normal. Charging flow returns to normal.

14:34 Pressurizer PORV PCV-456A reseats for the final time; the valve cycled 23 times during the 15-minute period.

14:35 Letdown restored to service; reactor coolant system pressure is maintained below pressurizer PORV setpoint for remainder of event.

14:37 Site watch reported Breaker 345-60 has visible damage.

14:47 Fire protection informed to commence fire impairments for LOOP.

15:00 Fire protection discussed with control room that the station did not have fire water system available. Reestablishing fire water was not a priority for operations at this time.

15:01 Natural circulation flow verified per EMG ES-02, Reactor Trip Response, Attachment A.

15:02 One hour continuous fire watch compensatory measures were not established.

15:30 Restored spent fuel pool cooling.

15:50 Completed EMG ES-02, Reactor Trip Response.

15:51 Commenced EMG ES-04, Natural Circulation Cooldown.

16:45 Senior reactor operator reviewing post-trip review trends identifies possible water leak inside containment; suspect essential service water based on containment parameters. 345kV East Bus re-energized from La Cygne line by closing Breaker 345-120. The air disconnects for Breaker 345-60 were opened first.

16:56 Shift manager directed the site watch to rack out the motor-driven fire pump breaker. Site watch made several attempts to prime and start the temporary diesel-driven fire pump.

17:00 Closed Transformer No. 7 Breaker 13-48 to energize Train A Safety Bus from offsite source.

17:09 Exited the Notification of Unusual Event.

Additional Event Information. The following event details are provided as additional information about the event. This additional information was not factored in the modeling of this analysis due to the negligible risk impact. See References 2 and 3 for further details.

The turbine-driven auxiliary feedwater pump (AFW) pump experienced an inadvertent actuation of the over-speed trip mechanism while the operators were shutting it down after it had operated continuously for 12.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . Inspectors determined that inadequate preventive maintenance caused of the mechanical over-speed trip was inadequate engagement between the head lever and tappet nut on the turbine control mechanism. The potential of the turbine-driven AFW pump to trip due to this deficiency is limited to seismic, or other jarring events; therefore, the reliability of pump was not changed for this analysis.

In addition to the over-speed trip upon pump shutdown, the turbine-driven AFW pump was run for several hours with flow dynamics inconsistent with its long-term operation.

LER 482/12-001 4

Inspectors concluded that the pump bearings were neither damaged nor experienced any detectable wear. The operation of the pump outside of its normal operating condition was considered an equipment qualification issue that might affect its long-term operation, but it was not a factor in response for this event.

A generator field ground alarm was received for EDG B; the generator had been operating for 22.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months when the alarm came in and continued to operate normally for another 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months until it was no longer needed. Since, the diesel fulfilled its mission time; no changes to the EDG reliability were made for this analysis.

Two hours and 43 minutes into the event, a senior reactor operator reviewing post trip review trends identified a possible water leak inside containment. It was later determined that the water leak was about 5 gpm from the essential service water (ESW) system piping at Reactor Containment Air Cooler C. Inspectors concluded that the leak in the ESW system was too small to challenge the function of the system (even if the leak had not been as quickly isolated during the event). The team concluded that the pipe pitting corrosion experienced during recent history was unlikely to produce leaks of a size that could challenge the system function based on historical problems and non-destructive examination results for system piping.

The count rate on source range nuclear instrument NI-31 began to increase when post-trip reactor power was decreasing as expected on NI-32 (this occurred with all rods inserted and the reactor shutdown). The licensee had previous experience that showed that, as reactor cavity temperature increased upon a loss of reactor cavity cooling (in this case as a result of the LOOP), the count rate on NI-31 would increase. This resulted in having only one reliable source range nuclear instrument remaining operable until reactor cavity temperatures decreased during the plant cooldown, which took about seven hours.

However, the licensee can monitor and credit the Gamma Metrics detectors in addition to the source range nuclear instruments and was able to comply with Technical Specifications under these conditions.

Temporary modifications were performed to restore power to chemistry and health physics equipment to support reactor coolant chemistry sampling. Additional temporary modifications were performed to power other non-vital loads, such as auxiliary building sump pumps and emergency diesel generator air compressors. These modifications were not required to safely shutdown the plant.

The licensee performed an emergency hydrogen purge of the main generator to prevent dangerous hydrogen leakage because the battery powering the seal oil pumps was being depleted; and later they had a tractor trailer of CO2 delivered to purge the hydrogen from the main generator, since the installed CO2 system had not been functional since 2008.

Simplified Electrical Drawing. Figure 1 provides a simplified drawing of the electrical distribution systems for Wolf Creek Generating Station.

LER 482/12-001 5

Figure 1. Simplified Electrical Drawing for Wolf Creek Generating Station.

MODELING ASSUMPTIONS Analysis Type. The Wolf Creek Generating Station Station Standardized Plant Analysis Risk (SPAR) model created in April 2012 was used for this event analysis. This event was modeled as a switchyard-related LOOP initiating event.

Analysis Rules. The ASP program uses Significance Determination Process results for degraded conditions when available. A licensee performance deficiency (PD) was identified in connection with the S/U Transformer fault. The PD involved the licensee failure to identify that electrical maintenance contractors had failed to install insulating sleeves on two wires that affected the differential current protection circuit. This affected safety-related equipment on January 13, 2012, when the startup transformer experienced a spurious trip and lockout during a plant trip because the two un-insulated wires touched and provided a false high phase differential signal to the protective relaying circuit. The protective lockout caused a prolonged loss of offsite power to Train B equipment. The SDP assessment of risk of this PD was finalized on September 13, 2012 (References 2-4); resulting in a YELLOW finding (i.e., substantial safety significance). However, the ASP Program performs independent analysis for events involving reactor trips. In addition, any SSC that was determined to be degraded, failed, or unavailable due to test/maintenance during the event is factored into the ASP initiating event analysis (regardless of whether the failures or degradations are due to licensee PD).

LER 482/12-001 6

Key Modeling Assumptions. The following modeling assumptions were determined to be vital to this event analysis:

This analysis models the January 13, 2012 reactor trip at Wolf Creek Generating Station as a switchyard-related LOOP initiating event.

Recovery of offsite power within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months was assumed to fail. For recovery durations of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or more, credit for operators potentially restoring offsite power is given. See Recovery Analysis for additional details.

Due to the loss of instrument air causing letdown isolation and increase in charging flow, Pressurizer Power-Operated Relief Valve (PORV) PCV-456A cycled open and closed 23 times.

The other PORV (PCV-455A) was isolated via its block valve due to excessive leakage.

Due to the LOOP, power for the motor-driven fire pump was unavailable. The design of the system is such that the installed diesel-driven fire pump would have started in response to the LOOP; however, it had been out-of-service since September 13, 2011, when it had catastrophically failed during its monthly functionality test. As a compensatory measure, a temporary diesel-driven fire pump had been installed in accordance with the plant fire protection impairment program. At the time of the LOOP the pump suction, pump case, minimum flow line, discharge manifold, and pump discharge lines for the temporary pump had been drained to prevent freezing. During the event response it took operators over 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months to successfully start the pump to provide fire water. Therefore, during a postulated station blackout (SBO), fire water would be unavailable to supply alternate cooling to the lube oil coolers for the safety injection pumps and centrifugal charging pump.

Basic Event Probability Changes. The following initiating event frequencies and basic event probabilities were modified for this event analysis:

The switchyard-related LOOP initiating event probability (IE-LOOPSC) was set 1.0 to represent the operational event that occurred at Wolf Creek Generating Station on January 13, 2012. All other initiating events probabilities were set to zero.

The basic event ACP-TFM-FC-XMR01 (Failure of 345-13.8kV Startup Transformer XMR01) was set to TRUE because of the Phase B fault on the SUT during the event.

There were 23 open/close cycles of PORV PCV-456A to limit pressure after the reactor and turbine trips. Therefore, the basic events PPR-SRV-CO-L (PORVs Open during Loop) and PPR-SRV-CO-SBO (PORVs Open during SBO) were set to TRUE. In addition, the failure probability for basic event PPR-SRV-OO-456A (PORV 456A FAILS to Reclose After Opening) was changed to 2.2x10-3 via binomial expansion to account for the increased probability that the valve could stick open.

The basic event PPR-MOV-FC-HV8000A (PORV 455A Block Valve HV8000A Closed during Power) was set to TRUE because the valve was closed during the event.

The basic event FWS-EDP-TM-FP01PB (Diesel-Driven Fire Water Pump FP01PB Unavailable Due to Test and/or Maintenance) was set to TRUE to account for unavailability of this pump during the event. No additional modeling of the temporary diesel-drive fire

LER 482/12-001 7

water pump was included in this analysis because of the long time it took operators to prime and start the pump during the event.

The default diesel generator mission times were changed to reflect the actual time offsite power was restored to the first vital bus (approximately 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months ). Since the overall fail-to-run is made up of two separate factors, the mission times for these factors were set to the following: ZT-DGN-FR-E = 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (base case value) and ZT-DGN-FR-L = 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Recovery Analysis. The time required to restore offsite power to plant emergency equipment is a significant factor in modeling the CCDP given a LOOP. The LOOP/SBO modeling within the SPAR models include various sequence-specific power recovery factors that are based on the time available to recover offsite power to prevent core damage. For a sequence involving failure of all of the cooling sources (e.g., postulated SBO with a failure of turbine-driven AFW pump), approximately one hour would be available to recover offsite power to avoid core damage. Sequences involving successful early inventory control and decay heat removal, but failure of long-term decay heat removal, would give operators several hours to recover offsite power prior to core damage.

In this analysis, offsite power recovery probabilities are based on:

Known information about when power was restored to the switchyard and the first safety

bus, A determination on whether offsite power could have been restored sooner given a postulated SBO, and Estimated probabilities of failing to realign power to an emergency bus given offsite power was (or could have been) restored to the switchyard.

Offsite power was restored to the first safety bus (Train A Safety Bus) two hours and 58 minutes after the LOOP occurred. Inspectors concluded that operator could have restored power sooner in the event of a blackout condition; however, due to complications associated with restoring offsite power to the switchyard (i.e., re-aligning power to the East Bus from the La Cygne Line) recovery of offsite power to a safety bus within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months was assumed to fail. Therefore, the recovery action OEP-XHE-XL-N01H (Operator Fails to Recover Offsite Power in 1 Hour) was set to TRUE for this analysis. Credit was given for offsite power recovery for applicable times greater than one hour.

The SPAR-H Human Reliability Analysis Method (References 5 and 6) was used to estimate non-recovery probabilities as a function of time following restoration of offsite power to the switchyard.1 Tables 1 and 2 provide the key qualitative information for this recovery and the performance shaping factor (PSFs) adjustments required for the quantification of offsite power recovery events for times greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months using SPAR-H.

1 The dominant contributor to failure to recover offsite power to plant safety-related loads in this analysis is operators failing to restore proper breaker line-ups. Hardware failures are assumed to be negligible (due to their much lower failure probabilities) in this recovery analysis.

LER 482/12-001 8

Table 1. Key Qualitative Information for Offsite Power Recovery after 1 Hour.

Definition The definition for overall recovery is the operators failure to align the La Cygne line to the East Bus and close breaker to re-energize the Train A Safety Bus in 2 to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months (depending on the sequence).

Description and Event Context Depending on postulated failures of the EDGs, reactor coolant pump (RCP) seals (due to unavailability of seal injection/cooling), the availability of the turbine-driven AFW pump, and the time until the station batteries are depleted, operators would have between 2-8 hours to re-energize prior to core uncovery.

Operator Action Success Criteria For successful recovery, operators would have to open the air disconnects for Breaker 345-60, and close Breaker 345-120 to energize the East Bus from La Cygne line. Operators would then have to close Transformer No. 7 Breaker 13-48 to energize the Train A Safety Bus. The time available for operators to perform this action would be a minimum of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months (given the failure of RCP seals).

Nominal Cues Loss of voltage on both safety buses:

No voltage indicated on safety buses.

Deenergized safety equipment (e.g., EDGs, CCW, and charging).

Procedural Guidance Operators used OFN NB-035, Loss of Offsite Power Restoration, and SYS NB-320, De-energizing and Energizing ESF Transformers, to restore power to the Train A Safety Bus.

Diagnosis/Action This recovery action contains diagnosis and action activities.

Table 2. SPAR-H Evaluation for Offsite Power Recovery after 1 Hour.

PSF Multiplier Diagnosis / Action Notes Time Available 0.01 / 1 Complications involving restoring power to the Train A Safety Bus would prevent the restoration (diagnosis and action) of power within an hour. For recovery actions with 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or more available, approximately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (at a minimum) would be available to perform the actions required to re-energize a safety bus prior to core uncovery. Therefore, the diagnosis PSF for available time is assigned as Expansive Time (i.e.,

x0.01; time available is >2 times nominal and >30 minutes).

Sufficient time exists to perform the action component of the offsite power recovery; therefore, the action PSF for available time is set to Nominal. See Reference 6 for guidance on apportioning time between the diagnosis and action components of an HFE.

Stress 2 / 1 The PSF for diagnosis stress is assigned a value of High Stress (i.e., x2) due to the postulated SBO and that core damage will occur if operators fail to restore power to a safety bus.

The PSF for action stress was not determined to be a performance driver for this HFE; and therefore, was assigned a value of Nominal (i.e., x1).

LER 482/12-001 9

PSF Multiplier Diagnosis / Action Notes Complexity 2 / 1 The PSF for diagnosis complexity is assigned a value of Moderately Complex (i.e., x2) because operators would have to deal with multiple equipment unavailabilities and the concurrent actions/multiple procedures during a LOOP and postulated SBO.

The PSF for action complexity was not determined to be a performance driver for this HFE; and therefore, was assigned a value of Nominal (i.e., x1).

Procedures Experience/Training, Ergonomics/HMI, Fitness for Duty, Work Processes 1 /1 No event information is available to warrant a change in these PSFs (diagnosis or action) from Nominal for this HFE.

Offsite power recovery actions with at least two hours of available time are calculated using the following SPAR-H formula:

Power Recovery HEP = (Product of Diagnosis PSFs

Nominal Diagnosis HEP) +

(Product of Action PSFs

Nominal Action HEP)

= (0.04

0.01) + (1

0.001) = 1x10-3 Therefore, the human error probabilities for offsite power recovery action after 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , OEP-XHE-XL-NR02HSC (Operator Fails to Recover Offsite Power in 2 Hours), OEP-XHE-XL-NR03HSC (Operator Fails to Recover Offsite Power in 3 Hours), OEP-XHE-XL-NR04HSC (Operator Fails to Recover Offsite Power in 4 Hours), OEP-XHE-XL-NR06HSC (Operator Fails to Recover Offsite Power in 6 Hours), and OEP-XHE-XL-NR08HSC (Operator Fails to Recover Offsite Power in 8 Hours) are calculated to be 1x10-3.

ANALYSIS RESULTS Conditional Core Damage Probability. The point estimate conditional core damage probability (CCDP) for this event is 4.7x10-4.

Dominant Sequence. The dominant accident sequence is LOOPSC (Loss of Offsite Power Switchyard-Related) Sequence 16-04-06 (CCDP = 2.1x10-4) which contributes 44% of the total internal events CCDP. Additional sequences that contribute greater than 1% of the total internal events CCDP are provided in Appendix A. The dominant sequence is shown graphically in Figures B-1, B-2, and B-3 in Appendix B.

The events and important component failures in LOOPSC Sequence 16-04-06 are:

Switchyard-related LOOP occurs, Reactor scram succeeds, Emergency power fails, AFW succeeds, Power-operated relief valves successfully close (if opened),

Rapid secondary depressurization succeeds, RCP seal cooling fails,

LER 482/12-001 10 RCP Seal 1 integrity is maintained, RCP Seal 2 fails, Operators successfully restore offsite power within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , High-pressure injection fails, Secondary side cooldown succeeds, Low-pressure injection succeeds, and Low-pressure recirculation fails.

REFERENCES

1. Wolf Creek Generating Station, Licensee Event Report 2012-001, Failure of 345 kV Switchyard Breaker Due to Internal Fault Resulting in Reactor Trip and Coincident Loss of Offsite Power, dated April 9, 2012 (ML12080A215).

2. U.S. Nuclear Regulatory Commission, Wolf Creek Nuclear Operating Corporation - NRC Augmented Inspection Team Report 05000482/2012008, dated April 4, 2012 (ML12095A414).

3. U.S. Nuclear Regulatory Commission, Wolf Creek Nuclear Operating Corporation - NRC Augmented Inspection Team Follow-Up Report 05000482/2012009; Preliminary Yellow Finding, dated August 6, 2012 (ML12227A919).

4. U.S. Nuclear Regulatory Commission, Wolf Creek Generating Station - Final Significance Determination of Yellow Finding and Notice of Violation, NRC Inspection Report 05000482/2012010, dated September 21, 2012 (ML12265A310).

5. Idaho National Laboratory, NUREG/CR-6883, The SPAR-H Human Reliability Analysis Method, August 2005 (ML051950061).

6. Idaho National Laboratory, INL/EXT-10-18533, SPAR-H Step-by-Step Guidance, May 2011 (ML112060305).

LER 482/12-001 A-1 Appendix A: Analysis Results Summary of Conditional Event Changes Event Description Cond.

Value Nominal Value ACP-TFM-FC-XMR01 FAILURE OF 345-13.8KV STARTUP XFORMER XMR01 TRUE 2.27E-5 FWS-EDP-TM-FP01PB DIESEL DRIVEN FIRE WATER PUMP FP01PB UNAVAILABLE DUE TO T/M TRUE 7.19E-3 IE-LOOPSCa LOSS OF OFFSITE POWER INITIATOR (SWITCHYARD-RELATED) 1.00E+0 1.04E-2 OEP-XHE-XL-NR01HSC OPERATOR FAILS TO RECOVER OFFSITE POWER IN 1 HOUR (SWITCHYARD)

TRUE 4.01E-1 OEP-XHE-XL-NR02HSC OPERATOR FAILS TO RECOVER OFFSITE POWER IN 2 HOURS (SWITCHYARD) 1.00E-3 2.24E-1 OEP-XHE-XL-NR03HSC OPERATOR FAILS TO RECOVER OFFSITE POWER IN 3 HOURS (SWITCHYARD) 1.00E-3 1.45E-1 OEP-XHE-XL-NR04HSC OPERATOR FAILS TO RECOVER OFFSITE POWER IN 4 HOURS (SWITCHYARD) 1.00E-3 1.02E-1 OEP-XHE-XL-NR08HSC OPERATOR FAILS TO RECOVER OFFSITE POWER IN 8 HOURS (SWITCHYARD) 1.00E-3 3.77E-2 PPR-MOV-FC-HV8000A PORV 455A BLOCK VALVE HV8000A CLOSED DURING POWER TRUE 3.00E-3 PPR-SRV-CO-L PORVS/SRVS OPEN DURING LOOP TRUE 1.48E-1 PPR-SRV-CO-SBO PORVS/SRVS OPEN DURING SBO TRUE 3.70E-1 PPR-SRV-OO-456A PORV 456A FAILS TO RECLOSE AFTER OPENING 2.20E-2 9.66E-4 ZT-DGN-FR-L DIESEL GENERATOR FAILS TO RUN 2.17E-3 2.47E-2

a.

All other initiating event probabilities were set to zero.

Dominant Sequence Results Only items contributing at least 1.0% to the total CCDP are displayed.

Event Tree Sequence CCDP

% Contribution Description LOOPSC 16-04-6 2.08E-4 44.1%

/RPS, EPS, /AFW-B, /PORV-B, /RSD-B, /BP1, BP2,

/OPR-04H, HPI, /SSC, /LPI, LPR LOOPSC 16-45 1.20E-4 25.5%

/RPS, EPS, AFW-B, OPR-01H, DGR-01H LOOPSC 16-42 4.80E-5 10.2%

/RPS, EPS, /AFW-B, PORV-B, OPR-01H, DGR-01H LOOPSC 15 3.14E-5 6.7%

/RPS, /EPS, AFW-L, FAB-L LOOPSC 05 2.36E-5 5.0%

/RPS, /EPS, /AFW-L, PORV-L, /HPI-L, /OPR-02H,

/SSC, RHR, HPR LOOPSC 16-07-6 1.04E-5 2.2%

/RPS, EPS, /AFW-B, /PORV-B, /RSD-B, BP1, /BP2,

/OPR-08H, HPI, /SSC, /LPI, LPR LOOPSC 02-02-07 7.62E-6 1.6%

/RPS, /EPS, /AFW-L, /PORV-L, LOSC-L, /RSD-L,

/BP1, BP2, /OPR-02H, /FW, HPI, /SSC1, /LPI, LPR LOOPSC 16-04-2 4.96E-6 1.1%

/RPS, EPS, /AFW-B, /PORV-B, /RSD-B, /BP1, BP2,

/OPR-04H, /HPI, /SSC, LPR Total 4.71E-4 100.0%

LER 482/12-001 A-2 Referenced Fault Trees Fault Tree Description AFW-B AUXILIARY FEEDWATER AFW-L WOLF CREEK AFW USING LOOP-FTF FAULT TREE FLAGS FAULT TREE BP1 RCP SEAL STAGE 1 INTEGRITY (BINDING/POPPING)

BP2 RCP SEAL STAGE 2 INTEGRITY (BINDING/POPPING)

DGR-01H OPERATOR FAILS TO RECOVER EMERGENCY DIESEL IN 1 HOUR EPS EMERGENCY POWER FAB-L FEED AND BLEED HPI HIGH PRESSURE INJECTION HPR HIGH PRESSURE RECIRC LOSC-L WOLF CREEK RCPSL USING LOOP-FTF FAULT TREE FLAGS LPR LOW PRESSURE RECIRC OPR-01H OPERATOR FAILS TO RECOVER OFFSITE POWER IN 1 HOUR PORV-B WOLF CREEK PORVs/SRVs OPEN DURING STATION BLACKOUT PORV-L PORVs ARE CLOSED RHR RESIDUAL HEAT REMOVAL SSC SECONDARY SIDE COOLDOWN Cutset Report - LOOPSC 16-04-06 Only items contributing at least 1% to the total are displayed.

CCDP Total%

Cutset 2.08E-4 100 Displaying 1680 of 1680 Cutsets.

1 2.03E-5 9.77 IE-LOOPSC,EPS-DGN-FR-NE02,ESW-MDP-TM-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 2

1.55E-5 7.45 IE-LOOPSC,ESW-FAN-CF-GDFANR,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 3

7.74E-6 3.72 IE-LOOPSC,ESW-TSA-CF-01ABS,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 4

7.65E-6 3.68 IE-LOOPSC,EPS-DGN-FS-NE02,ESW-MDP-TM-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 5

6.33E-6 3.04 IE-LOOPSC,ACP-CRB-CC-NB0209,ESW-MDP-TM-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 6

6.06E-6 2.91 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-FAN-FR-CGD01A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 7

5.59E-6 2.69 IE-LOOPSC,ESW-FAN-FR-CGD01A,ESW-MDP-TM-1B,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 8

5.59E-6 2.69 IE-LOOPSC,ESW-FAN-FR-CGD01B,ESW-MDP-TM-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 9

5.29E-6 2.54 IE-LOOPSC,DCP-BCH-TM-BC24,ESW-MDP-TM-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 10 4.49E-6 2.16 IE-LOOPSC,ESW-MDP-CF-START,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 11 4.44E-6 2.14 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-TSA-FS-FEF01A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 12 4.21E-6 2.02 IE-LOOPSC,ESW-FAN-CF-GDFANS,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 13 4.10E-6 1.97 IE-LOOPSC,ESW-MDP-TM-1B,ESW-TSA-FS-FEF01A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 14 4.10E-6 1.97 IE-LOOPSC,ESW-MDP-TM-1A,ESW-TSA-FS-FEF01B,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 15 3.91E-6 1.88 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-MDP-FS-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2

LER 482/12-001 A-3 CCDP Total%

Cutset 16 3.71E-6 1.79 IE-LOOPSC,ESW-MOV-CF-HV009192,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 17 3.60E-6 1.73 IE-LOOPSC,ESW-MDP-FS-1A,ESW-MDP-TM-1B,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 18 3.60E-6 1.73 IE-LOOPSC,ESW-MDP-FS-1B,ESW-MDP-TM-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 19 3.46E-6 1.66 IE-LOOPSC,ESW-TSA-CF-01ABR,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 20 3.24E-6 1.56 IE-LOOPSC,EPS-DGN-FR-NE02,ESW-FAN-FR-CGD01A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 21 3.03E-6 1.46 IE-LOOPSC,ESW-MDP-CF-RUN,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 22 2.87E-6 1.38 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-XHE-XR-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 23 2.76E-6 1.33 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-MOV-CC-EFHV0091,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 24 2.65E-6 1.27 IE-LOOPSC,ESW-MDP-TM-1B,ESW-XHE-XR-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 25 2.65E-6 1.27 IE-LOOPSC,ESW-MDP-TM-1A,ESW-XHE-XR-1B,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 26 2.55E-6 1.22 IE-LOOPSC,ESW-MDP-TM-1B,ESW-MOV-CC-EFHV0091,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 27 2.55E-6 1.22 IE-LOOPSC,ESW-MDP-TM-1A,ESW-MOV-CC-EFHV0092,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 28 2.41E-6 1.16 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-FAN-FS-CGD01A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 29 2.38E-6 1.14 IE-LOOPSC,EPS-DGN-FR-NE02,ESW-TSA-FS-FEF01A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 30 2.23E-6 1.07 IE-LOOPSC,ESW-FAN-FS-CGD01A,ESW-MDP-TM-1B,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 31 2.23E-6 1.07 IE-LOOPSC,ESW-FAN-FS-CGD01B,ESW-MDP-TM-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 32 2.09E-6 1.01 IE-LOOPSC,EPS-DGN-FR-NE02,ESW-MDP-FS-1A,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 Cutset Report - LOOPSC 16-45 Only items contributing at least 1% to the total are displayed.

CCDP Total%

Cutset 1.20E-4 100 Displaying 5250 of 5250 Cutsets.

1 3.79E-6 3.16 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FR-NE01,EPS-DGN-TM-NE02,EPS-XHE-XL-NR01H 2

3.79E-6 3.16 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FR-NE02,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H 3

3.60E-6 3

IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-CF-NE012R,EPS-XHE-XL-NR01H 4

3.50E-6 2.92 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FR-NE02,EPS-XHE-XL-NR01H,ESW-MDP-TM-1A 5

3.50E-6 2.92 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FR-NE01,EPS-XHE-XL-NR01H,ESW-MDP-TM-1B 6

2.67E-6 2.22 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-XHE-XL-NR01H,ESW-FAN-CF-GDFANR 7

2.03E-6 1.69 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FR-NE01,EPS-DGN-FR-NE02,EPS-XHE-XL-NR01H 8

1.53E-6 1.27 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H,ESW-SYS-TM-TRAINB

LER 482/12-001 A-4 CCDP Total%

Cutset 9

1.43E-6 1.19 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FS-NE01,EPS-DGN-TM-NE02,EPS-XHE-XL-NR01H 10 1.43E-6 1.19 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FS-NE02,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H 11 1.33E-6 1.11 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-XHE-XL-NR01H,ESW-TSA-CF-01ABS 12 1.32E-6 1.1 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FS-NE02,EPS-XHE-XL-NR01H,ESW-MDP-TM-1A 13 1.32E-6 1.1 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-FS-NE01,EPS-XHE-XL-NR01H,ESW-MDP-TM-1B 14 1.24E-6 1.04 IE-LOOPSC,AFW-TDP-FR-PAL02,EPS-DGN-CF-NE012S,EPS-XHE-XL-NR01H Cutset Report - LOOPSC 16-42 Only items contributing at least 1% to the total are displayed.

CCDP Total%

Cutset 4.80E-5 100 Displaying 1407 of 1407 Cutsets.

1 2.11E-6 4.39 IE-LOOPSC,EPS-DGN-FR-NE02,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 2

2.11E-6 4.39 IE-LOOPSC,EPS-DGN-FR-NE01,EPS-DGN-TM-NE02,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 3

2.00E-6 4.16 IE-LOOPSC,EPS-DGN-CF-NE012R,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 4

1.94E-6 4.05 IE-LOOPSC,EPS-DGN-FR-NE01,EPS-XHE-XL-NR01H,ESW-MDP-TM-1B,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 5

1.94E-6 4.05 IE-LOOPSC,EPS-DGN-FR-NE02,EPS-XHE-XL-NR01H,ESW-MDP-TM-1A,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 6

1.48E-6 3.08 IE-LOOPSC,EPS-XHE-XL-NR01H,ESW-FAN-CF-GDFANR,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 7

1.13E-6 2.35 IE-LOOPSC,EPS-DGN-FR-NE01,EPS-DGN-FR-NE02,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 8

8.47E-7 1.76 IE-LOOPSC,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H,ESW-SYS-TM-TRAINB,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 9

7.93E-7 1.65 IE-LOOPSC,EPS-DGN-FS-NE02,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 10 7.93E-7 1.65 IE-LOOPSC,EPS-DGN-FS-NE01,EPS-DGN-TM-NE02,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 11 7.41E-7 1.54 IE-LOOPSC,EPS-XHE-XL-NR01H,ESW-TSA-CF-01ABS,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 12 7.31E-7 1.52 IE-LOOPSC,EPS-DGN-FS-NE01,EPS-XHE-XL-NR01H,ESW-MDP-TM-1B,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 13 7.31E-7 1.52 IE-LOOPSC,EPS-DGN-FS-NE02,EPS-XHE-XL-NR01H,ESW-MDP-TM-1A,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 14 6.91E-7 1.44 IE-LOOPSC,EPS-DGN-CF-NE012S,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 15 6.56E-7 1.37 IE-LOOPSC,ACP-CRB-CC-NB0209,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 16 6.56E-7 1.37 IE-LOOPSC,ACP-CRB-CC-NB0112,EPS-DGN-TM-NE02,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 17 6.05E-7 1.26 IE-LOOPSC,ACP-CRB-CC-NB0209,EPS-XHE-XL-NR01H,ESW-MDP-TM-1A,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 18 6.05E-7 1.26 IE-LOOPSC,ACP-CRB-CC-NB0112,EPS-XHE-XL-NR01H,ESW-MDP-TM-1B,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A

LER 482/12-001 A-5 CCDP Total%

Cutset 19 5.79E-7 1.21 IE-LOOPSC,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H,ESW-FAN-FR-CGD01B,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 20 5.79E-7 1.21 IE-LOOPSC,EPS-DGN-TM-NE02,EPS-XHE-XL-NR01H,ESW-FAN-FR-CGD01A,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 21 5.48E-7 1.14 IE-LOOPSC,DCP-BCH-TM-BC24,EPS-DGN-TM-NE01,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 22 5.48E-7 1.14 IE-LOOPSC,DCP-BCH-TM-BC21,EPS-DGN-TM-NE02,EPS-XHE-XL-NR01H,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 23 5.35E-7 1.11 IE-LOOPSC,EPS-XHE-XL-NR01H,ESW-FAN-FR-CGD01A,ESW-MDP-TM-1B,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 24 5.35E-7 1.11 IE-LOOPSC,EPS-XHE-XL-NR01H,ESW-FAN-FR-CGD01B,ESW-MDP-TM-1A,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 25 5.06E-7 1.05 IE-LOOPSC,DCP-BCH-TM-BC24,EPS-XHE-XL-NR01H,ESW-MDP-TM-1A,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 26 5.06E-7 1.05 IE-LOOPSC,DCP-BCH-TM-BC21,EPS-XHE-XL-NR01H,ESW-MDP-TM-1B,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A Cutset Report - LOOPSC 15 Only items contributing at least 1% to the total are displayed.

CCDP Total%

Cutset 3.14E-5 100 Displaying 6681 of 6681 Cutsets.

1 1.47E-6 4.67 IE-LOOPSC,AFW-ACX-FR-SGF02B,AFW-TDP-FR-PAL02,EPS-DGN-TM-NE01 2

1.42E-6 4.51 IE-LOOPSC,AFW-ACX-TM-SGF02B,AFW-TDP-FR-PAL02,EPS-DGN-TM-NE01 3

1.35E-6 4.31 IE-LOOPSC,AFW-ACX-FR-SGF02B,AFW-TDP-FR-PAL02,ESW-MDP-TM-1A 4

1.31E-6 4.16 IE-LOOPSC,AFW-ACX-TM-SGF02B,AFW-TDP-FR-PAL02,ESW-MDP-TM-1A 5

1.21E-6 3.84 IE-LOOPSC,AFW-MDP-TM-PAL01B,AFW-TDP-FR-PAL02,EPS-DGN-FR-NE01 6

7.86E-7 2.5 IE-LOOPSC,AFW-ACX-FR-SGF02B,AFW-TDP-FR-PAL02,EPS-DGN-FR-NE01 7

7.59E-7 2.41 IE-LOOPSC,AFW-ACX-TM-SGF02B,AFW-TDP-FR-PAL02,EPS-DGN-FR-NE01 8

5.67E-7 1.8 IE-LOOPSC,AFW-TDP-FR-PAL02,AFW-XHE-XR-SGF02B,EPS-DGN-TM-NE01 9

5.37E-7 1.71 IE-LOOPSC,AFW-MDP-FS-PAL01B,AFW-TDP-FR-PAL02,EPS-DGN-TM-NE01 10 5.23E-7 1.66 IE-LOOPSC,AFW-TDP-FR-PAL02,AFW-XHE-XR-SGF02B,ESW-MDP-TM-1A 11 4.96E-7 1.58 IE-LOOPSC,AFW-MDP-FS-PAL01B,AFW-TDP-FR-PAL02,ESW-MDP-TM-1A 12 4.54E-7 1.44 IE-LOOPSC,AFW-MDP-TM-PAL01B,AFW-TDP-FR-PAL02,EPS-DGN-FS-NE01 13 4.54E-7 1.44 IE-LOOPSC,AFW-ACX-FS-SGF02B,AFW-TDP-FR-PAL02,EPS-DGN-TM-NE01 14 4.18E-7 1.33 IE-LOOPSC,AFW-ACX-FS-SGF02B,AFW-TDP-FR-PAL02,ESW-MDP-TM-1A 15 3.76E-7 1.2 IE-LOOPSC,ACP-CRB-CC-NB0112,AFW-MDP-TM-PAL01B,AFW-TDP-FR-PAL02 16 3.32E-7 1.06 IE-LOOPSC,AFW-MDP-TM-PAL01B,AFW-TDP-FR-PAL02,ESW-FAN-FR-CGD01A 17 3.14E-7 1

IE-LOOPSC,AFW-MDP-TM-PAL01B,AFW-TDP-FR-PAL02,DCP-BCH-TM-BC21 Cutset Report - LOOPSC 05 Only items contributing at least 1% to the total are displayed.

CCDP Total%

Cutset 2.36E-5 100 Displaying 1921 of 1921 Cutsets.

1 8.14E-7 3.45 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-ACX-FR-SGL10A 2

7.86E-7 3.33 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-ACX-TM-SGL10A 3

7.51E-7 3.18 IE-LOOPSC,ESW-MDP-TM-1B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-ACX-FR-SGL10A

LER 482/12-001 A-6 CCDP Total%

Cutset 4

6.29E-7 2.67 IE-LOOPSC,EPS-DGN-TM-NE02,HPI-XHE-XM-RECIRC,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 5

5.80E-7 2.46 IE-LOOPSC,ESW-MDP-TM-1B,HPI-XHE-XM-RECIRC,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 6

4.36E-7 1.85 IE-LOOPSC,EPS-DGN-FR-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-ACX-FR-SGL10A 7

4.21E-7 1.78 IE-LOOPSC,EPS-DGN-FR-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-ACX-TM-SGL10A 8

3.37E-7 1.43 IE-LOOPSC,EPS-DGN-FR-NE02,HPI-XHE-XM-RECIRC,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 9

3.14E-7 1.33 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-XHE-XR-SGL10A 10 3.14E-7 1.33 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-XHE-XR-P1A 11 3.14E-7 1.33 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-XHE-XR-HX1A 12 3.03E-7 1.28 IE-LOOPSC,EPS-DGN-TM-NE02,HPI-MOV-CC-8804A,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 13 3.03E-7 1.28 IE-LOOPSC,EPS-DGN-TM-NE02,HPI-MOV-OO-8814A,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 14 3.03E-7 1.28 IE-LOOPSC,EPS-DGN-TM-NE02,HPI-MOV-OO-8814B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 15 3.03E-7 1.28 IE-LOOPSC,EPS-DGN-TM-NE02,HPI-MOV-CC-8807A,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 16 3.03E-7 1.28 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-MOV-OO-8812A 17 3.03E-7 1.28 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-MOV-CC-8811A 18 3.03E-7 1.28 IE-LOOPSC,CCW-MOV-CC-HV101,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 19 2.98E-7 1.26 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-MDP-FS-P1A 20 2.90E-7 1.23 IE-LOOPSC,ESW-MDP-TM-1B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-XHE-XR-SGL10A 21 2.90E-7 1.23 IE-LOOPSC,ESW-MDP-TM-1B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-XHE-XR-P1A 22 2.90E-7 1.23 IE-LOOPSC,ESW-MDP-TM-1B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-XHE-XR-HX1A 23 2.79E-7 1.18 IE-LOOPSC,ESW-MDP-TM-1B,HPI-MOV-CC-8804A,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 24 2.79E-7 1.18 IE-LOOPSC,ESW-MDP-TM-1B,HPI-MOV-OO-8814A,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 25 2.79E-7 1.18 IE-LOOPSC,ESW-MDP-TM-1B,HPI-MOV-OO-8814B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 26 2.79E-7 1.18 IE-LOOPSC,ESW-MDP-TM-1B,HPI-MOV-CC-8807A,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 27 2.79E-7 1.18 IE-LOOPSC,ESW-MDP-TM-1B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-MOV-OO-8812A 28 2.79E-7 1.18 IE-LOOPSC,ESW-MDP-TM-1B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-MOV-CC-8811A

LER 482/12-001 A-7 CCDP Total%

Cutset 29 2.79E-7 1.18 IE-LOOPSC,CCW-MOV-CC-HV101,ESW-MDP-TM-1B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A 30 2.75E-7 1.17 IE-LOOPSC,ESW-MDP-TM-1B,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-MDP-FS-P1A 31 2.52E-7 1.07 IE-LOOPSC,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR02HSC,/PPR-MOV-FC-HV8000B,PPR-SRV-OO-456A,RHR-ACX-FS-SGL10A Cutset Report - LOOPSC 16-07-6 Only items contributing at least 1% to the total are displayed.

CCDP Total%

Cutset 1.04E-5 100 Displaying 759 of 759 Cutsets.

1 1.02E-6 9.77 IE-LOOPSC,EPS-DGN-FR-NE02,ESW-MDP-TM-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 2

7.75E-7 7.45 IE-LOOPSC,ESW-FAN-CF-GDFANR,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 3

3.87E-7 3.72 IE-LOOPSC,ESW-TSA-CF-01ABS,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 4

3.82E-7 3.68 IE-LOOPSC,EPS-DGN-FS-NE02,ESW-MDP-TM-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 5

3.16E-7 3.04 IE-LOOPSC,ACP-CRB-CC-NB0209,ESW-MDP-TM-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 6

3.03E-7 2.91 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-FAN-FR-CGD01A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 7

2.79E-7 2.69 IE-LOOPSC,ESW-FAN-FR-CGD01A,ESW-MDP-TM-1B,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 8

2.79E-7 2.69 IE-LOOPSC,ESW-FAN-FR-CGD01B,ESW-MDP-TM-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 9

2.65E-7 2.54 IE-LOOPSC,DCP-BCH-TM-BC24,ESW-MDP-TM-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 10 2.25E-7 2.16 IE-LOOPSC,ESW-MDP-CF-START,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 11 2.22E-7 2.14 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-TSA-FS-FEF01A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 12 2.10E-7 2.02 IE-LOOPSC,ESW-FAN-CF-GDFANS,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 13 2.05E-7 1.97 IE-LOOPSC,ESW-MDP-TM-1B,ESW-TSA-FS-FEF01A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 14 2.05E-7 1.97 IE-LOOPSC,ESW-MDP-TM-1A,ESW-TSA-FS-FEF01B,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 15 1.95E-7 1.88 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-MDP-FS-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 16 1.86E-7 1.79 IE-LOOPSC,ESW-MOV-CF-HV009192,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 17 1.80E-7 1.73 IE-LOOPSC,ESW-MDP-FS-1A,ESW-MDP-TM-1B,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 18 1.80E-7 1.73 IE-LOOPSC,ESW-MDP-FS-1B,ESW-MDP-TM-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 19 1.73E-7 1.66 IE-LOOPSC,ESW-TSA-CF-01ABR,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 20 1.62E-7 1.56 IE-LOOPSC,EPS-DGN-FR-NE02,ESW-FAN-FR-CGD01A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2

LER 482/12-001 A-8 CCDP Total%

Cutset 21 1.52E-7 1.46 IE-LOOPSC,ESW-MDP-CF-RUN,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 22 1.43E-7 1.38 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-XHE-XR-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 23 1.38E-7 1.33 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-MOV-CC-EFHV0091,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 24 1.32E-7 1.27 IE-LOOPSC,ESW-MDP-TM-1B,ESW-XHE-XR-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 25 1.32E-7 1.27 IE-LOOPSC,ESW-MDP-TM-1A,ESW-XHE-XR-1B,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 26 1.27E-7 1.22 IE-LOOPSC,ESW-MDP-TM-1B,ESW-MOV-CC-EFHV0091,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 27 1.27E-7 1.22 IE-LOOPSC,ESW-MDP-TM-1A,ESW-MOV-CC-EFHV0092,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 28 1.21E-7 1.16 IE-LOOPSC,EPS-DGN-TM-NE02,ESW-FAN-FS-CGD01A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 29 1.19E-7 1.14 IE-LOOPSC,EPS-DGN-FR-NE02,ESW-TSA-FS-FEF01A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 30 1.11E-7 1.07 IE-LOOPSC,ESW-FAN-FS-CGD01A,ESW-MDP-TM-1B,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 31 1.11E-7 1.07 IE-LOOPSC,ESW-FAN-FS-CGD01B,ESW-MDP-TM-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 32 1.05E-7 1.01 IE-LOOPSC,EPS-DGN-FR-NE02,ESW-MDP-FS-1A,/OEP-XHE-XL-NR08HSC,RCS-MDP-LK-BP1,/RCS-MDP-LK-BP2 Cutset Report - LOOPSC 02-02-07 Only items contributing at least 1% to the total are displayed.

CCDP Total%

Cutset 7.62E-6 100 Displaying 582 of 582 Cutsets.

1 1.44E-6 18.8 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,EPS-DGN-TM-NE02,RCS-MDP-LK-BP2 2

1.32E-6 17.4 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,ESW-MDP-TM-1B,RCS-MDP-LK-BP2 3

7.68E-7 10.1 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,EPS-DGN-FR-NE02,RCS-MDP-LK-BP2 4

3.09E-7 4.06 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,ESW-SYS-TM-TRAINB,RCS-MDP-LK-BP2 5

2.89E-7 3.8 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,EPS-DGN-FS-NE02,RCS-MDP-LK-BP2 6

2.52E-7 3.31 IE-LOOPSC,CCW-AOV-CF-TV2930,CCW-XHE-XM-BYPASS,RCS-MDP-LK-BP2 7

2.39E-7 3.14 IE-LOOPSC,ACP-CRB-CC-NB0209,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,RCS-MDP-LK-BP2 8

2.11E-7 2.77 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,ESW-FAN-FR-CGD01B,RCS-MDP-LK-BP2 9

2.00E-7 2.63 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,DCP-BCH-TM-BC24,RCS-MDP-LK-BP2 10 1.91E-7 2.51 IE-LOOPSC,CCW-SYS-TM-TRAINB,ESW-FAN-FR-CGD01A,RCS-MDP-LK-BP2 11 1.55E-7 2.03 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,ESW-TSA-FS-FEF01B,RCS-MDP-LK-BP2 12 1.40E-7 1.84 IE-LOOPSC,CCW-SYS-TM-TRAINB,ESW-TSA-FS-FEF01A,RCS-MDP-LK-BP2

LER 482/12-001 A-9 CCDP Total%

Cutset 13 1.36E-7 1.79 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,ESW-MDP-FS-1B,RCS-MDP-LK-BP2 14 1.33E-7 1.75 IE-LOOPSC,ACP-BAC-LP-NB01,CCW-XHE-XM-ISOLATE,RCS-MDP-LK-BP2 15 1.23E-7 1.62 IE-LOOPSC,CCW-SYS-TM-TRAINB,ESW-MDP-FS-1A,RCS-MDP-LK-BP2 16 1.00E-7 1.31 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,ESW-XHE-XR-1B,RCS-MDP-LK-BP2 17 9.63E-8 1.26 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,ESW-MOV-CC-EFHV0092,RCS-MDP-LK-BP2 18 9.06E-8 1.19 IE-LOOPSC,CCW-SYS-TM-TRAINB,ESW-XHE-XR-1A,RCS-MDP-LK-BP2 19 8.73E-8 1.15 IE-LOOPSC,CCW-SYS-TM-TRAINB,ESW-MOV-CC-EFHV0091,RCS-MDP-LK-BP2 20 8.42E-8 1.11 IE-LOOPSC,CCW-CFG-AP-TRB,CCW-XHE-XM-TRNA,ESW-FAN-FS-CGD01B,RCS-MDP-LK-BP2 21 7.63E-8 1

IE-LOOPSC,CCW-SYS-TM-TRAINB,ESW-FAN-FS-CGD01A,RCS-MDP-LK-BP2 Cutset Report - LOOPSC 16-04-02 Only items contributing at least 1% to the total are displayed.

CCDP Total%

Cutset 4.96E-6 100 Displaying 4382 of 4382 Cutsets.

1 9.55E-8 1.93 IE-LOOPSC,ACP-BAC-LP-NG03,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 2

8.81E-8 1.78 IE-LOOPSC,ACP-BAC-LP-NG03,ESW-MDP-TM-1B,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 3

5.70E-8 1.15 IE-LOOPSC,EPS-DGN-FR-NE02,EPS-DGN-TM-NE01,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2,RHR-ACX-FR-SGL10A 4

5.70E-8 1.15 IE-LOOPSC,EPS-DGN-FR-NE01,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2,RHR-ACX-FR-SGL10A 5

5.51E-8 1.11 IE-LOOPSC,EPS-DGN-FR-NE01,EPS-DGN-TM-NE02,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2,RHR-ACX-TM-SGL10A 6

5.51E-8 1.11 IE-LOOPSC,EPS-DGN-FR-NE02,EPS-DGN-TM-NE01,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2,RHR-ACX-TM-SGL10A 7

5.40E-8 1.09 IE-LOOPSC,EPS-DGN-CF-NE012R,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2,RHR-ACX-FR-SGL10A 8

5.26E-8 1.06 IE-LOOPSC,EPS-DGN-FR-NE01,ESW-MDP-TM-1B,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2,RHR-ACX-FR-SGL10A 9

5.22E-8 1.05 IE-LOOPSC,EPS-DGN-CF-NE012R,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2,RHR-ACX-TM-SGL10A 10 5.11E-8 1.03 IE-LOOPSC,ACP-BAC-LP-NG03,EPS-DGN-FR-NE02,/OEP-XHE-XL-NR04HSC,RCS-MDP-LK-BP2 Referenced Events Event Description Probability ACP-BAC-LP-NB01 4160 VAC BUS NB01 FAILS 3.33E-5 ACP-BAC-LP-NG03 480 VAC BUS NG03 FAILS 3.33E-5 ACP-CRB-CC-NB0112 ESF TRANSFORMER XNB01 BREAKER FAILS TO OPEN 2.39E-3 ACP-CRB-CC-NB0209 ESF TRANSFORMER XNB02 BREAKER FAILS TO OPEN 2.39E-3 AFW-ACX-FR-SGF02B AFW MDP B ROOM COOLER FAILS TO RUN 2.59E-3 AFW-ACX-FS-SGF02B AFW MDP B ROOM COOLER FAILS TO START 8.00E-4 AFW-ACX-TM-SGF02B AFW MDP B ROOM COOLER UNAVAILABLE DUE TO T&M 2.50E-3 AFW-MDP-FS-PAL01B AFW MOTOR-DRIVEN PUMP 1B FAILS TO START 9.47E-4

LER 482/12-001 A-10 Event Description Probability AFW-MDP-TM-PAL01B AFW MDP UNAVAILABLE DUE TO TEST AND MAINTENANCE 3.98E-3 AFW-TDP-FR-PAL02 TURBINE DRIVEN FEED PUMP PAL02 FAILS TO RUN 3.95E-2 AFW-XHE-XR-SGF02B OP FAILS TO RESTORE AFW MDP B ROOM COOLER AFTER T&M 1.00E-3 CCW-AOV-CF-TV2930 CCW HTX BYPASS CONTROL VALVES TV-29 & 30 FAIL TO CLOSE 6.30E-5 CCW-CFG-AP-TRB FRACTION OF TIME CCW MDP 1B1AND 1D ARE INITIALLY RUNNING 5.00E-1 CCW-MOV-CC-HV101 RHR HTX EJ01A COOLING VLV EGHV101 FAILS TO OPEN 9.63E-4 CCW-SYS-TM-TRAINB CCW TRAIN B IS IN MAINTAINANCE (PSA) 4.53E-4 CCW-XHE-XM-BYPASS OPERATOR FAILS TO CLOSE CCW HTX BYPASS VALVE LOCALLY 2.00E-2 CCW-XHE-XM-ISOLATE OPERATOR FAILS TO ISOLATE IDLE CCW LOOP 2.00E-2 CCW-XHE-XM-TRNA OPERATOR FAILS TO START AND ALIGN CCW TRAIN A 1.00E-3 DCP-BCH-TM-BC21 BATTERY CHARGER BC-21 UNAVALIBLE DUE T& M 2.00E-3 DCP-BCH-TM-BC24 BATTERY CHARGER BC-24 UNAVALIBLE DUE T& M 2.00E-3 EPS-DGN-CF-NE012R COMMON CAUSE FAILURE OF DIESEL GENERATORS TO RUN 1.04E-4 EPS-DGN-CF-NE012S COMMON CAUSE FAILURE OF DIESEL GENERATORS TO START 3.61E-5 EPS-DGN-FR-NE01 DIESEL GENERATOR NE01 FAILS TO RUN 7.68E-3 EPS-DGN-FR-NE02 DIESEL GENERATOR NE02 FAILS TO RUN 7.68E-3 EPS-DGN-FS-NE01 DIESEL GENERATOR NE01 FAILS TO START 2.89E-3 EPS-DGN-FS-NE02 DIESEL GENERATOR NE02 FAILS TO START 2.89E-3 EPS-DGN-TM-NE01 DG NE01 UNAVAILABLE DUE TO TEST AND MAINTENANCE 1.43E-2 EPS-DGN-TM-NE02 DG NE02 UNAVAILABLE DUE TO TEST AND MAINTENANCE 1.43E-2 EPS-XHE-XL-NR01H OPERATOR FAILS TO RECOVER EMERGENCY DIESEL IN 1 HOUR 8.71E-1 ESW-FAN-CF-GDFANR ESW ROOM HVAC FANS CGD01A & 1B FAIL TO RUN 7.76E-5 ESW-FAN-CF-GDFANS ESW ROOM HVAC FANS CGD01A & 1B FAIL TO START 2.11E-5 ESW-FAN-FR-CGD01A ESW TRAIN A HVAC FAN CGD01A FAILS TO RUN 2.11E-3 ESW-FAN-FR-CGD01B ESW TRAIN B HVAC FAN CGD01B FAILS TO RUN 2.11E-3 ESW-FAN-FS-CGD01A ESW TRAIN A HVAC FAN CGD01A FAILS TO START 8.42E-4 ESW-FAN-FS-CGD01B ESW TRAIN B HVAC FAN CGD01B FAILS TO START 8.42E-4 ESW-MDP-CF-RUN ESW PUMPS FAIL FROM COMMON CAUSE TO RUN 1.52E-5 ESW-MDP-CF-START ESW PUMPS FAIL FROM COMMON CAUSE TO START 2.25E-5 ESW-MDP-FS-1A ESW TRAIN A MDP 1A FAILS TO START 1.36E-3 ESW-MDP-FS-1B ESW TRAIN B MDP 1B FAILS TO START 1.36E-3 ESW-MDP-TM-1A ESW TRAIN A MDP 1A UNAVAILABLE DUE TO T&M 1.32E-2 ESW-MDP-TM-1B ESW TRAIN A MDP 1B UNAVAILABLE DUE TO T&M 1.32E-2 ESW-MOV-CC-EFHV0091 FAILURE OF ESW A TRAVELING SCREEN WASH VALVE TO OPEN 9.63E-4 ESW-MOV-CC-EFHV0092 FAILURE OF ESW B TRAVELING SCREEN WASH VALVE TO OPEN 9.63E-4 ESW-MOV-CF-HV009192 FAILURE OF ESW A & B TRAVELING SCREEN WASH VALVES TO OPEN 1.86E-5 ESW-SYS-TM-TRAINB SWS TRAIN B UNAVAILBLE DUE TO DRAINAGE OF ESW TRAIN B (PSA) 3.09E-3

LER 482/12-001 A-11 Event Description Probability ESW-TSA-CF-01ABR FAILURE OF ESW A & B TRAVELING SCREENS FEF01A & B TO RUN 1.73E-5 ESW-TSA-CF-01ABS FAILURE OF ESW A & B TRAVELING SCREENS FEF01A & B TO START 3.87E-5 ESW-TSA-FS-FEF01A FAILURE OF ESW A TRAVELING SCREEN TO START 1.55E-3 ESW-TSA-FS-FEF01B FAILURE OF ESW A TRAVELING SCREEN FEF01B TO START 1.55E-3 ESW-XHE-XR-1A OPERATOR FAILS TO RESTORE ESW MDP 1A AFTER T&M 1.00E-3 ESW-XHE-XR-1B OPERATOR FAILS TO RESTORE ESW MDP 1B AFTER T&M 1.00E-3 HPI-MOV-CC-8804A SI/CVC RHR HTX A MOV 8804A FAILS TO OPEN 9.63E-4 HPI-MOV-CC-8807A FAILURE OF SUCTION MOV SI-8807A 9.63E-4 HPI-MOV-OO-8814A SI PUMP P1A MINFLOW VALVE 8814A FAILS TO CLOSE 9.63E-4 HPI-MOV-OO-8814B SI PUMP P1B MINFLOW VALVE 8814B FAILS TO CLOSE 9.63E-4 HPI-XHE-XM-RECIRC OPERATOR FAILS TO START HIGH PRESSURE RECIRC 2.00E-3 IE-LOOPSC LOSS OF OFFSITE POWER INITIATOR (SWITCHYARD-RELATED) 1.00E+0 PPR-SRV-OO-456A PORV 456A FAILS TO RECLOSE AFTER OPENING 2.20E-2 RCS-MDP-LK-BP1 RCP SEAL STAGE 1 INTEGRITY (BINDING/POPPING OPEN)

FAILS 1.25E-2 RCS-MDP-LK-BP2 RCP SEAL STAGE 2 INTEGRITY (BINDING/POPPING OPEN)

FAILS 2.00E-1 RHR-ACX-FR-SGL10A RHR ROOM COOLER SGL10A FAILS TO RUN 2.59E-3 RHR-ACX-FS-SGL10A RHR ROOM COOLER SGL10A FAILS TO START 8.00E-4 RHR-ACX-TM-SGL10A RHR A ROOM COOLER SGL10A UNAVAILABLE DUE TO T&M 2.50E-3 RHR-MDP-FS-P1A RHR PUMP P1A FAILS TO START 9.47E-4 RHR-MOV-CC-8811A PUMP P1A SUMP SUCTN VLV 8811A FAILS TO OPEN 9.63E-4 RHR-MOV-OO-8812A PUMP P1A RWST SUCTN VLV 8812A FAILS TO CLOSE 9.63E-4 RHR-XHE-XR-HX1A OPERATOR FAILS TO RESTORE HTX 1A AFTER T&M 1.00E-3 RHR-XHE-XR-P1A OPERATOR FAILS TO RESTORE TRAIN P1A AFTER T&M 1.00E-3 RHR-XHE-XR-SGL10A OPERATOR FAILS TO RESTORE RHR A ROOM COOLER AFTER T&M 1.00E-3

LER 482/12-001 B-1 Appendix B: Key Event Trees Figure B-1. Wolf Creek Generating Station Switchyard-Related LOOP Event Tree.

IE-LOOPSC LOSS OF OFFSITE POWER INITIATOR (SWITCHYARD-RELATED)

RPS REACTOR TRIP LOOP-FTF EPS EMERGENCY POWER AFW AUXILIARY FEEDWATER AVAILABLE PORV PORVs/SRVs ARE CLOSED LOSC-FTF LOSC LOSS OF SEAL COOLING HPI HIGH PRESSURE INJECTION FAB FEED AND BLEED OPR-02H OFFSITE POWER RECOVERY IN 2 HRS OPR-06H OFFSITE POWER RECOVERY IN 6 HRS SSC COOLDOWN (PRIMARY AND SECONDARY)

RHR RESIDUAL HEAT REMOVAL HPR HIGH PRESSURE RECIRC End State (Phase - CD) 1 OK LOSC-L 2

LOOP-1 PORV-L 3

OK 4

OK 5

CD 6

OK 7

CD 8

OK HPR-L 9

CD HPI-L 10 CD AFW-L 11 OK 12 CD 13 OK HPR-L 14 CD FAB-L 15 CD 16 SBO 17 ATWS 18 CD

LER 482/12-001 B-2 Figure B-2. Wolf Creek Generating Station SBO Event Tree.

LOOP-FTF EPS EMERGENCY POWER SBO-FTF AFW-B AUXILIARY FEEDWATER PORV PORVs/SRVs ARE CLOSED SBO-FTF RSD-B RAPID SECONDARY DEPRESS BP1 RCP SEAL STAGE 1 INTEGRITY (BINDING/POPPING)

O1 RCP SEAL STAGE 1 INTEGRITY (O-RING EXTRUSION)

BP2 RCP SEAL STAGE 2 INTEGRITY (BINDING/POPPING)

O2 RCP SEAL STAGE 2 INTEGRITY (O-RING EXTRUSION)

OPR-08H OFFSITE POWER RECOVERY (IN 8 HR)

DGR-08H DIESEL GENERATOR RECOVERY (IN 8 HR)

End State (Phase - CD) 21 gpm/rcp 1

OK 2

OK 3

SBO-4 182 gpm/rcp 4

SBO-1 OPR-04H 5

OK DGR-04H 6

CD 76 gpm/rcp 7

SBO-1 8

OK 9

SBO-4 480 gpm/rcp 10 SBO-1 OPR-02H 11 OK DGR-02H 12 CD 21 gpm/rcp 13 SBO-2 14 OK 15 SBO-4 172 gpm/rcp 16 SBO-2 OPR-03H 17 OK DGR-03H 18 CD 182 gpm/rcp 19 SBO-2 OPR-03H 20 OK DGR-03H 21 CD 61 gpm/rcp 22 SBO-2 OPR-06H 23 OK DGR-06H 24 CD 300 gpm/rcp 25 SBO-2 OPR-02H 26 OK DGR-02H 27 CD 300 gpm/rcp 28 SBO-2 OPR-02H 29 OK DGR-02H 30 CD 76 gpm/rcp 31 SBO-2 OPR-06H 32 OK DGR-06H 33 CD 300 gpm/rcp 34 SBO-2 OPR-02H 35 OK DGR-02H 36 CD 480 gpm/rcp 37 SBO-2 OPR-02H 38 OK DGR-02H 39 CD PORV-B 40 SBO-2 OPR-01H 41 OK DGR-01H 42 CD 43 SBO-3 OPR-01H 44 OK DGR-01H 45 CD

LER 482/12-001 B-3 Figure B-3. Wolf Creek Generating Station SBO-1 Event Tree.

OPR OFFSITE POWER RECOVERY HPI HIGH PRESSURE INJECTION SSC COOLDOWN (PRIMARY AND SECONDARY)

LPI LOW PRESSURE INJECTION HPR HIGH PRESSURE RECIRC LPR LOW PRESSURE RECIRC End State (Phase - CD) 1 OK 2

CD 3

OK 4

CD 5

OK 6

CD 7

CD 8

CD

July 12, 2013 MEMORANDUM TO:

Harold K. Chernoff, Chief Operating Experience Branch Division of Inspection and Regional Support Office of Nuclear Reactor Regulation FROM:

Roy K. Mathew, Acting Chief

/RA/

Electrical Engineering Branch Division of Engineering Office of Nuclear Reactor Regulation

SUBJECT:

SAFETY EVALUATION REGARDING WOLF CREEK GENERATING STATION - AUGMENTED INSPECTION - LOSS OF OFFSITE POWER AND NOTIFICATION OF UNUSUAL EVENT, ISSUE FOR RESOLUTION 2012-004.

(TAC NO. ME8004)

The Electrical Engineering Branch has reviewed the Issue For Resolution 2012-004, AWolf Creek Generating Station-Augmented Inspection - Loss Of Offsite Power and Notification Of Unusual Event.@ Enclosed is our safety evaluation. This completes our review and evaluation efforts for TAC NO. ME8004.

Enclosure:

As stated CONTACTS: Prem P. Sahay, NRR/DE/EEEB (301) 415-8439 Peter J. Kang, NRR/DE/EEEB (301) 415-6800

July 11, 2013 MEMORANDUM TO:

Harold K. Chernoff, Chief Operating Experience Branch Division of Inspection and Regional Support Office of Nuclear Reactor Regulation FROM:

Roy K. Mathew, Acting Chief

/RA/

Electrical Engineering Branch Division of Engineering Office of Nuclear Reactor Regulation

SUBJECT:

SAFETY EVALUATION REGARDING WOLF CREEK GENERATING STATION - AUGMENTED INSPECTION - LOSS OF OFFSITE POWER AND NOTIFICATION OF UNUSUAL EVENT, ISSUE FOR RESOLUTION 2012-004.

(TAC NO. ME8004)

The Electrical Engineering Branch has reviewed the Issue For Resolution 2012-004, AWolf Creek Generating Station-Augmented Inspection - Loss Of Offsite Power and Notification Of Unusual Event.@ Enclosed is our safety evaluation. This completes our review and evaluation efforts for TAC NO. ME8004.

Enclosure:

As stated CONTACTS: Prem P. Sahay, NRR/DE/EEEB (301) 415-8439 Peter J. Kang, NRR/DE/EEEB (301) 415-6800 DISTRIBUTION: JRobles FIssa RidsNrrDeEeeb NRR_DE_DPR ADAMS ACCESSION NO: ML13109A234 OFFICE DE/EEEB DE/EEEB DE/EEEB (A)BC NAME PSahay PKang RMathew DATE 7/11/2013 7/11/2013 7/12/2013 OFFICIAL RECORD COPY

ENCLOSURE EVALUATION REGARDING WOLF CREEK GENERATING STATION AUGMENTED INSPECTION - LOSS OF OFFSITE POWER AND NOTIFICATION OF UNUSUAL EVENT, ISSUE FOR RESOLUTION 2012-004 (TAC NO. ME8004) 1.0 PURPOSE The purpose of this Issue For Resolution (IFR) is to evaluate the root cause of the LOOP event, the safety significance, determine similar events at other plants, and provide recommendations for issuing generic communications or other regulatory actions. This IFR applies to all operating and new reactors.

2.0 BACKGROUND

According to the License Event Report (LER) 2012-001-00, Wolf Creek unit 1 experienced an unplanned automatic shutdown from full power operation and a coincident loss of offsite power (LOOP) for greater than 15 minutes, resulting in the declaration of a Notification of Unusual Event (NUE) on January 13, 2012 at 14:03 Central Standard Time (CST). A Wolf Creek Site Watch Operator reported to the Control Room that the main generator output breaker 345-60 had experienced a failure with substantial visual damage. At 1537 hours0.0178 days 0.427 hours 0.00254 weeks 5.848285e-4 months the Wolf Creek Turbine Building Watch notified the Control Room of a dropped flag from a Differential relay actuation (487/T1B) on a panel MA104D for the Startup Transformer. This failure and faulted condition of the breaker 345-60 resulted in actuation of protective relays for the East Bus Primary lockout, East Bus Secondary lockout, and 345-60 breaker failure. These relay actuations caused the opening of switchyard breakers and isolated the east switchyard bus, resulting in a turbine trip and subsequent reactor trip. To counter this loss of power, a "fast bus transfer" occurred that realigned the power supply for the non-safety buses to the Startup Transformer (XMR01). As soon as the fast bus transfer was complete, the 487/T1 'B' Phase Startup Transformer differential relay actuated per design. The Startup Transformer Differential relay (487/T) sends inputs to the 286/T1 lockout relay, which initiates de-energization of the Startup Transformer. This protective sequence generates a signal to isolate the Startup Transformer power supply to ESF Transformer XNB02. Additionally, this Startup Transformer 286/T1 lockout relay feeds protection circuitry in the WCGS switchyard to open switchyard breakers to isolate the West 345 kilo Volt (kV) bus and de-energize the Startup Transformer.

This sequence of events, which isolated and de-energized the WCGS switchyard East 345 kV and West 345 kV buses, resulted in the loss of offsite AC electrical power to the unit. The turbine trip initiated a reactor trip. All control rods inserted into the core and all reactor coolant pumps tripped per design. The undervoltage relays on safety related 4.16 kV engineered safety features (ESF) buses NB01 and NB02 actuated and initiated a loss of power DG start signal for the automatic start of both emergency diesel generators (DGs). Both DGs started and supplied power to the 4.16 kV ESF buses with loads sequenced onto the buses per design.

At 1700 CST offsite power was restored to the East 345 kV bus, Transformer XNB01, and the NB01 bus. With the restoration of an operable offsite circuit, the Unusual Event was terminated at 1709 CST. At 1721 CST the 'A' DG was placed in a standby condition.

On February 13, 2012, at 2008 CST, an attempt was made to start the 'A' Reactor Coolant Pump (RCP) for troubleshooting. This start attempt resulted in the second loss of electrical power to the Startup Transformer. The licensees investigation revealed that the Startup Transformer 487/T1 'B' phase Differential relay and the 286/T1 lockout relay were tripped as well as the 94F West Bus Secondary Differential relay in the Switchyard, which had initiated the automatic opening of Switchyard breakers resulting in de-energization of the switchyard West 345 kV bus.

In its Root Cause Report CR 47653 (IIT 2012-001), the licensee stated that the January 13, 2012 event was the third instance of LOOP experienced by Wolf Creek within past four years.

The first loss of offsite power occurred on April 7, 2008 (LER No. 4822008004), when one offsite source (the Switchyard No. 7 Transformer) was out of service, and a human error isolated the one remaining offsite source (the West Bus) from the Startup Transformer, resulting in a loss of offsite power. The unit was in Mode 6 with the Reactor de-fueled at the time. The second LOOP event occurred in August 19, 2009 (LER No. 4822009002), when both offsite sources were lost due to a lightning strike on its transmission line. The unit was in Mode 1 both times. The second LOOP was caused by offsite transmission grid events and conditions.

LOOP on January 13, 2013 was the third occurrence for the Wolf Creek Plant.

3.0 ROOT CAUSE EVALUATION The Wolf Creek Switchyard and its connections to the unit are shown in the Attachment 2. The Wolf Creek unit is connected to the Switchyard through main generator breaker to provide generator output to the Switchyard and transmission grid and through the main Step up Transformer to provide offsite power to the plant equipment.

In its root cause report, the licensee stated the following:

1. The most likely failure mechanism of the Generator Output breaker phase/pole C was the internal particulate or contaminations in the breaker internal environment that set up a path for a flashover across the insulator surface. However, due to the extensive damage incurred by the breaker pole, it is not possible to definitively identify the exact internal location and source of the particulate material.

2. The initial testing and troubleshooting was performed on the Startup Transformer and associated protective relaying. Troubleshooting did not reveal any deficiencies that could have caused the LOOP on January 13, 2012. During the original troubleshooting effort the junction boxes that contained the Current Transformer (CT) junction boxes were not visually inspected. Standard/regular electrical tests individually verified XMR01 differential CT circuits for each phase as not having any short or ground. However, the standard electrical test configuration would not identify shorts between unused CT taps of different CTs or phases. Due to the lack of any monitoring at the time of the event the maintenance crew was not aware that the B phase Differential relay circuit was not generating the expected current, and phase shift. The point-to-point meggering between phase checks that eventually detected the CT short on the unused taps, is not a typical industry standard test used and thus was not originally implemented. As a result, the Startup Transformer was reenergized from off-site power at 1207 hours0.014 days 0.335 hours 0.002 weeks 4.592635e-4 months on February 3, 2012, with the later identified CT short still existing.

3. After the February 13, 2012, Startup Transformer (XMR01) differential trip (Failure Mode), troubleshooting on February 16, 2012, identified a short on XMR01 high side CT wires that feeds the differential protection scheme. During the troubleshooting, megger testing indicated a phase-to-phase short circuit between two unused high side CT taps (CT Wire W2 on A phase and W10 on B phase). Subsequent field inspections found two missing insulation sleeves on these CT wires, originating from last refueling outage vendor work on the transformer.

The following sequence of events is based on the excerpt from the licensee=s root cause report of the Wolf Creek event (Attachment 2). The sequence of events occurred in the following order (only important events are listed):

Sequence of Events Date - 01/13/2012 Event Time Summary of Event Event Description Wolf Creek Unit was operating at 100% power prior to this event.

14:02:54.740 Wolf Creek East Bus Diff (T = 0)

Switchyard supervisory point indicating the trip of an east buss differential relay.

14:02:54.753 Main Generator Switchyard BKR No.

345-60 is OPEN This point is a direct indication of breaker 345-60 opening. It indicates breaker open when all three phases of breaker 345-60 are open.

14:02:54.768 Wolf Creek 345-50 open 14:02:54.919 Startup Transformer lockout 286/T1 has actuated. 487/T1 B phase Start-up Transformer Differential target flagged (T)

Indication that Startup Transformer lockout 286/T1 has actuated. 487/T1 B phase Start-up Transformer Differential target flagged (T).

14:02:54.922 Startup transformer trip.

Indication in switchyard that the 286/T1 lockout has actuated in the plant. Switchyard cross trip relay 94P/W is in parallel with the plants 286/T1 lockout and they were both actuated by the S/U transformer 487/T1 differential relay. The 94P/W relay actuates the west bus lockout 86 P/W.

14:02:54.930 Wolf Creek West Bus Diff (Lockout)

Loss of Offsite Power occurred.

14:02:54.994 REAC MAIN TRIP BKR B is TRIPD Reactor tripped.

14:02:55.006 REAC MAIN TRIP BKR A is TRIPD Reactor tripped.

14:03:02.656 DG NE02 FDR BKR is CLOSD Emergency Diesel Generator started as designed.

14:03:02.953 DG NE01 FDR BKR is CLOSD Emergency Diesel Generator started as designed.

The Wolf Creek root cause investigation (CR 47653 (IIT 2012-001)) identified two key issues that resulted in the LOOP event, namely, failure to identify presence of the particulate or contaminations on the main generator output breaker phase/pole C and correct it and failure to identify two un-insulated terminal wires in contact (i.e. shorted) on the CT for Start up Transformer 487 differential relays. Both cases appear to be due to human errors.

The licensees Hardware Failure Analysis identified the most likely failure mechanism of the 345-60 Generator Output breaker to be particulate contamination in the breaker internal environment that set up a path for a flashover across the insulator surface. An effective maintenance program by the licensee would have detected and resolved the presence of particulates and could have avoided main generator output breaker failure.

On February 16, 2012, at approximately 2008 hours0.0232 days 0.558 hours 0.00332 weeks 7.64044e-4 months , with the plant in Mode 5, the A Reactor Coolant Pump (RCP) was started. This start attempt resulted in another protective lockout of the Startup Transformer. This transformer lockout resulted in the isolation of the Wolf Creek substation West bus and the loss of electrical power to the non-safety related 13.8 kV buses as well as B Train safety-related 4.16 kV bus NB02. While performing current transformer (CT) testing on interfaces with the Differential Relay protection zone, the licensee identified an electrical short in the phase A and B CT terminal wiring block. Two wires that were not insulated (as they should have been) were in contact, causing an electrical short and that resulted in Step up transformer differential relay actuation and tripping of transformer as designed. This CT terminal junction block was last worked during refueling outage RF18 by the vendor company, and had previously tested satisfactorily at the completion of work during RF18. Wolf Creek did not recognize the risk/consequence of having a vendor perform work in accordance with vendor procedures and processes, without established verification methods for ensuring work quality, thus resulting in an undetected human performance error.

Had the licensee established and implemented effective verification methods for ensuring work quality, an electrical short in the phase A and B CT terminal wiring block could have been identified and corrected and startup transformer differential relay actuation and startup transformer trip and LOOP could have been avoided.

The NRC dispatched an augmented inspection team to review the facts surrounding the event (NRC Inspection Report 05000482/2012008 dated March 4, 2012, Agencywide Documents Access and Management System (ADAMS) Accession Number ML12095A414). The team identified several unresolved items (URIs) requiring follow-up inspection. Specifically, one URI involved reviewing the root cause analysis of the main generator output breaker fault when it is completed and follow up actions, and the another URI involved reviewing the root cause analysis of the startup transformer fault when it is completed and follow up actions.

4.0 SAFETY SIGNIFICANCE The event is considered safety significant, as it resulted in unit trip, LOOP, and starting of the safety related equipment due to human performance errors.

In addition, the January 13, 2012, event was the second LOOP event caused by human error within four years. The first loss of offsite power occurred on April 7, 2008, when one offsite source (the Switchyard No. 7 Transformer) was out of service, and a human error isolated the one remaining offsite source (the West Bus) from the Startup Transformer, resulting in a loss of offsite power. The unit was in Mode 6 with the Reactor de-fueled at the time.

Had the licensee established and implemented an effective maintenance program including independent verification requirements for ensuring work quality and identification and elimination of human errors based on the lessons learned from April 7, 2008 plant event, Wolf Creek could have avoided another LOOP and unplanned plant trip on January 13, 2012.

5.0 RECENT LOOP EVENTS IN OTHER NUCLEAR PLANTS Oyster Creek experienced LOOP on July 23, 2012, due to an electrical fault on an offsite transmission line (outside plant). (ref. PNO-I-12-005)

Catawba Units 1 and 2 experienced LOOP on April 4, 2012, at 8:54 PM EDT. (ref. LER No. 2011-003-0)

Byron Units 1 and 2 experienced LOOP on January 30, 2012, at 10:18 AM (CST). (ref.

LER No. 2012-001-01)

Point Beach Nuclear plant Unit 1 declared NOUE following LOOP on November 27, 2011, at 2:38 AM (CST). (ref. LER No. 2011-001-00)

Browns Ferry Nuclear Plant Units 1, 2, and 3 declared NOUE due to LOOP on April 27, 2011, at 6:21 PM (EDT). (ref. LER No. 2011-001-00)

Surry Power Station Units 1 and 2 declared NOUE due to LOOP from a tornado on April 16, 2011, at 7:48 PM. (ref.LER No. 2011-001-00)

North Anna Units 1 and 2 experienced LOOP during seismic event on August 23, 2011.

(ref. LER No. 2011-003-00)

Calvert Cliff Unit 1 and 2 experienced Partial LOOP on February 18, 2010, at 8:24 AM (ref. 2010-001-01).

Point Beach Nuclear plant Unit 1 declared NOUE following LOOP on January 15, 2008.

(ref. LER No. 2008-001-00)

Two out of a total of eight LOOP events (including Wolf Creek January 13, 2012 event) in year 2011 and year 2012 were due to natural causes such as tornado and earthquakes. From above list of LOOP events, it is evident that overall LOOP events in years 2011 and 2012 have significantly increased (including Wolf Creek January 13, 2012 event) compare to year 2008, 2009 (Wolf Creek August 19, 2009 event) and 2010 and supports NRC concern on upward trend of the LOOP events in recent two years.

The staff reviewed the NRC Technical Review Group (TRG) Reports for the Year 2011 dated November 11, 2012 and 2012 (Agencywide Documents Access and Management System (ADAMS) Number ML12306A261) and finds that both reports highlighted the issue on the high number of LOOP/inoperable offsite power sources due to the equipment failure and/or human errors, consistent with the staffs finding on this IFR.

The staff also reviewed following active generic communications on the plant events resulting in LOOP:

1. Information Notice (IN) 2006-18, Significant Loss of Safety-Related Electrical Power at Forsmark Unit 1 in Sweden.

2. IN 2007-14, Loss of Offsite Power and Duel-Unit Trip at Catawba Nuclear Generating Station.

3. IN 2009-10, Transformer Failures - Recent Operating Experience.

6.0 IMPACT OF FREQUENCY OF LOOP ON STATION BLACKOUT COPING DURATION Regulatory Guide 1.155, August 1988, Station Blackout states, Based on Title 10 of the Code if Federal Regulation, Part 50.63 (10 CFR 50.63), all licensees and applicants are required to assess the capability of their plants to maintain adequate core cooling and appropriate containment integrity during a station blackout and to have procedures to cope with such an event. This guide presents a method acceptable to the NRC staff for determining the specified duration for which a plant should be able to withstand a station blackout in accordance with these requirements. The application of this method results in selecting a minimum acceptable station blackout duration capability from 2 to 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months , depending on a comparison of the plant's characteristics with those factors that have been identified as significantly affecting the risk from station blackout. These factors include redundancy of the onsite emergency ac power system (i.e., the number of diesel generators available for decay heat removal minus the number needed for decay heat removal), the reliability of onsite emergency ac power sources (e.g., diesel generators), the frequency of LOOP, and the probable time to restore offsite power.

Licensees may propose durations different from those specified in this guide. The basis for alternative durations would be predicated on plant-specific factors relating to the reliability of alternating current (AC) power systems such as those discussed in Reference 2.

As discussed above, the frequency of LOOP is one of the factors affecting SBO coping duration. If the frequency of LOOP has changed since last analysis, the coping duration is no longer valid.

7.0 CONCLUSION

Based on the above, the staff concludes the following:

1. The Wolf Creek event on January 13, 2012, appears to be plant specific as staff review of the operating experience database did not find similar plant events occurring in other nuclear plants.

2. The LOOP events in the US nuclear industry continued to rise for the year 2011 and 2012 compared to year 2008 and 2010 as evident from the LOOP events listed in Section 5.00.

3. Despite NRC concerns communicated to the nuclear industry in INs 2006-18, 2007-14 and 2009-10, number of LOOP events continue to increase in year 2011 and 2012.

8.0 RECOMMENDATIONS

1. This Issue for Resolution (IFR) Evaluation should be sent to all the Engineering Branch Chiefs/Division of Reactor Safety in the Regions including Region 2 Division of Construction Inspection. The regional inspectors should refer to this IFR when conducting inspections in maintenance and surveillance areas.

2. Although the January 13, 2012 plant events at Wolf Creek appear to be plant specific, and similar plant events have already been addressed in above INs, the staff finds that number of LOOP events occurring in the nuclear industry have suddenly increased in year 2011 and 2012. As such, the staff recommends issuing appropriate generic communication to address its concern on overall increase in LOOP events in recent years.

9.0 ATTACHMENTS (1)

Excerpt from Wolf Creek Root Cause Evaluation Report CR 47653 (IIT 2012-001)

Executive Summary (2)

Wolf Creek Nuclear Station Switchyard diagram and its connection to the unit (1 sheet)

Principal Contributor: Prem P. Sahay ATTACHMENT 1 Excerpt from Wolf Creek Root Cause Evaluation Report CR 47653 (IIT 2012-001) Executive Summary On January 13, 2012 Wolf Creek experienced a loss of offsite power, the third such instance experienced by Wolf Creek within the past four years. The first loss of offsite power (April 7, 2008) occurred when one offsite source (the Switchyard No. 7 Transformer) was out of service, and a human error isolated the one remaining offsite source (the West Bus) from the Startup Transformer, resulting in a loss of offsite power.

The unit was in Mode 6 with the Reactor de-fueled at the time. The second and third LOOP events occurred when both offsite sources were lost due to two failure mechanisms that occurred at approximately the same time (i.e., within cycles of one another). The unit was in Mode 1 both times. The second LOOP was caused by offsite transmission grid events and conditions. The first and third LOOPs initiated at Wolf Creek each involved a human error. Wolf Creek management established an Incident Investigation Team (IIT) on January 13, 2012 to perform a Root Cause Analysis (RCA) of the unplanned station shutdown coincident with a loss of offsite power (LOOP). The event occurred at approximately 1403 hours0.0162 days 0.39 hours 0.00232 weeks 5.338415e-4 months on January 13, 2012 and a Notification Of Unusual Event (NUE) was declared due to the LOOP lasting longer than 15 minutes. The IIT was chartered by and reported to the Vice President -

Strategic Projects. An event focus meeting was held on January 14, 2012 to commence the investigation.

Additionally, on 2/13/12 at approximately 2008 hours0.0232 days 0.558 hours 0.00332 weeks 7.64044e-4 months , with the plant in Mode 5 the A Reactor Coolant Pump (RCP) was started. This start attempt resulted in another protective lockout of the Startup Transformer. This transformer lockout resulted in the isolation of the Wolf Creek substation West bus and the loss of electrical power to the non-safety related 13.8 kV buses as well as B Train safety-related 4.16 kV bus NB02. Personnel interviews, reviews of pertinent documents, computer modeling of protective relay schemes of the applicable plant electrical buses, hardware failure analysis of the breaker 345-60 and potential transformer (PT) 113-1, and extensive hardware inspection and testing were used to generate the bases related to the causes and consequences associated with the causal factors identified. Two Event and Causal Factor (E&CF) Charts (overview and details) were developed using a detailed Sequence of Events (SOE) report. Fault Tree Analysis, Evidence and Action Matrix, Change Analysis, Barrier Analysis, Why Tree, and Safety Culture Analysis were used to identify causal factors and determine corrective actions. A Management Oversight and Risk Tree (MORT) analysis was used to evaluate completeness of the analysis and to identify or confirm areas of causality. Many Organizational and Programmatic elements, as well as technical, procedural, structural, and leadership factors, contributed to the Loss of Offsite Power event in January 2012. The IIT has developed corrective actions that are responsive to the Organizational and Programmatic contributors to the Loss of Offsite Power event. The collective data evaluated by the IIT demonstrates that Wolf Creek did not recognize the risk/consequence of having a vendor perform work, in accordance with vendor procedures and processes, without an established verification method for ensuring work quality, thus resulting in an undetected human performance error. Depending upon a third party to provide quality work was evident in the 2008 LOOP, as well as in the 2009 LOOP. The Hardware Failure Analysis identified the most likely failure mechanism of the 345-60 Generator Output breaker to be particulate in the breaker internal environment that set up a path for a flashover across the insulator surface. However, due to the extensive damage incurred by the breaker pole, it is not possible to definitively identify the exact internal location and source of the particulate material. Different theories exist regarding the source of the contamination and internal location of the initial arc.

CAUSES The identified Root and Contributing Causes:

Root Cause 1 Statement:

Internal particulate contamination caused the failure of the Generator Output breaker 345-60.

Root Cause 2 Statement:

Wolf Creek did not recognize the risk/consequence of having a vendor perform work, in accordance with vendor procedures and processes, without a Wolf Creek approved verification method for ensuring work quality, resulting in an undetected human performance error.

Contributing Cause 1 Statement: Wolf Creek personnel, at all levels, failed to implement and enforce the companys accountability model, primarily with respect to procedural use and adherence.

ATTACHMENT 2 Wolf Creek Nuclear Station Switchyard diagram and its connection to the unit (1 sheet)

May 16, 2013 MEMORADUM TO:

Michele G. Evans, Director Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation FROM:

Richard P. Correia, Director /RA/ D. Coe for Division of Risk Analysis Office of Nuclear Regulatory Research

SUBJECT:

TRANSMITTAL OF FINAL WOLF CREEK GENERATING STATION ACCIDENT SEQUENCE PRECURSOR ANALYSIS This memorandum transmits the final results of an accident sequence precursor (ASP) analysis of an operational event that occurred at Wolf Creek Generating Station on January 13, 2012.

This analysis has a final conditional core damage probability (CCDP) of 5x10-4 which is less than threshold for a significant precursor (i.e., CCDP greater than or equal to 1x10-3).

The Office of Nuclear Regulatory Research (RES) requested a formal analysis review from the licensee in accordance with U.S. Nuclear Regulatory Commission Regulatory Issue Summary 2006-24, Revised Review and Transmittal Process for Accident Sequence Precursor Analyses, because the analysis had a preliminary CCDP greater than 1x10-4. No comments were received from the licensee, and no additional comments from the Office of Nuclear Reactor Regulation (NRR) and Region IV staff were provided.

The ASP Program continues to systematically review licensee event reports (LERs) and all other event reporting information [e.g., inspection reports (IRs)] for potential precursors, and to analyze those events which have the potential to be precursors. The complete summary of FY 2012 ASP events will be provided in the upcoming Commission paper on the status of the ASP Program and Standardized Plant Analysis Risk (SPAR) Models due to be issued in October 2013.

Transmittal to Licensee Requested. We are requesting NRR to send the enclosed final ASP analysis to the licensee for their information. The ASP analysis will be made publically available after the analysis has been transmitted to the licensee. Please inform us when the ASP analysis has been sent to the licensee.

CONTACT:

Christopher Hunter, RES/DRA 301-251-7575

Final ASP Analysis Summary. A brief summary of the final ASP analysis, including the results, is provided below.

Multiple Switchyard Faults Cause Reactor Trip and Subsequent Loss of Offsite Power (January 2012) at Wolf Creek Generating Station. This event is documented in LER 482/12-001 and IRs 05000482/2012008, 05000482/2012009, and 05000482/2012010.

Event Summary. On January 13, 2012, at 2:02 p.m. CST, the site experienced a loss of offsite power (LOOP). The event resulted from two distinct faults. The first fault was on Phase C of the Main Generator Output Breaker 345-60. This fault resulted in the 345 kV East Bus differential relay protective logic to open Breakers 345-120, 345-90, 345-60, 13-48, and 69-16, which together de-energized the East Bus. This fault resulted in a main generator trip signal, and started the sequence of events to shift the source of power to most station loads from the Unit Auxiliary Transformer (UAT) to the Startup Transformer (SUT) in a sequence called a fast bus transfer. The second fault, a phase differential, occurred on Phase B of the SUT and resulted in the 345 kV West Bus differential relay protective logic opening Breakers 345-40, 345-70, and 345-110, de-energizing the remaining portions of the switchyard. The second fault also resulted in the SUT phase differential relay protective logic opening Breakers PA0110, PA0201, and PA0202.

Emergency Diesel Generators A and B automatically started and powered their respective safety buses approximately eight seconds after the start of the event. At 4:45 p.m., the 345kV East Bus was reenergized from the La Cygne line by closing Breaker 345-120, restoring offsite power to the Train A safety-related components (Bus NB01). On January 15th, operators restored offsite power to Bus NB02 by closing the Alternate Feeder Breaker NB0212 to power Train B from Train A once in Mode 5 and EDG B was secured. Electrical repairs were not completed until February 4th, when the SUT was returned to service and damaged wires and a bus potential transformer for Breakers PA0201 and PA0110 were replaced and the breakers were returned to service.

Summary of Analysis Results. This operational event resulted in a CCDP of 5x10-4. The detailed ASP analysis can be found in the Enclosure.

Risk Insights. According to the model assumptions used in the ASP analysis, the most likely core damage sequence is the mechanical failure of the reactor coolant pump seals (due loss of seal injection and cooling) which creates a small loss-of-coolant accident and the subsequent failure of low-pressure recirculation (from the combined likelihood of either equipment or operator failures) leading to the failure of heat removal after reasonably quick recovery of offsite power.

The second and third most likely core damage sequences involve a postulated station blackout condition (due to various emergency diesel generator and service water failures) that combined with the failure of either the turbine-driven auxiliary feedwater pump or failure of a power-operated relief valve to close (after it had opened) with failure of operators to restore offsite power within one hour.

In general, these results are consistent with LOOP events analyzed by ASP at pressurized-water reactors.

Sensitive Information. The detailed ASP analysis has been reviewed by my staff in accordance with SECY-04-0191, Withholding Sensitive Unclassified Information Concerning Nuclear Power Reactors from Public Disclosure, and it has been determined that it may be released to the public.

Enclosure:

1. Final ASP Analysis

ML13115A109 OFFICE RES/DRA/PRB RES/DRA/PRB RES/DRA RES NAME C. Hunter G. DeMoss D. Coe R. Correia (D.Coe for)

DATE 4/25/13 4/29/13 5/07/13 5/16/13

Enclosure 1

Final Precursor Analysis Accident Sequence Precursor Program - Office of Nuclear Regulatory Research Wolf Creek Generating Station Multiple Switchyard Faults Cause Reactor Trip and Subsequent Loss of Offsite Power Event Date: 01/13/2012 LER: 482/12-001 IRs: 50-482/12-08, 50-482/12-09, 50-482/12-10 CCDP = 5x10-4 EVENT

SUMMARY

Event Description. On January 13, 2012, at 2:02 p.m. CST, the site experienced a loss of offsite power (LOOP). The event resulted from two distinct faults. The first fault was on Phase C of the Main Generator Output Breaker 345-60. This fault resulted in the 345 kV East Bus differential relay protective logic to open Breakers 345-120, 345-90, 345-60, 13-48, and 69-16, which together de-energized the East Bus. As a result of the location of the fault on Phase C of Breaker 345-60, the main generator differential relay protective logic opened Breaker 345-50. This resulted in a main generator trip signal, and started the sequence of events to shift the source of power to most station loads from the Unit Auxiliary Transformer (UAT) to the Startup Transformer (SUT) in a sequence called a fast bus transfer. The fast bus transfer resulted in Breakers PA0211 and PA0101 opening, and Breakers PA0202 and PA0110 closing. This completed the fast bus transfer and now had the station loads aligned through the SUT.

The second fault, a phase differential, occurred on Phase B of the SUT and resulted in the 345 kV West Bus differential relay protective logic opening Breakers 345-40, 345-70, and 345-110, de-energizing the remaining portions of the switchyard. It also resulted in the SUT phase differential relay protective logic opening Breakers PA0110, PA0201, and PA0202. The sequence of events to this point all occurred in approximately 12 cycles (about 0.2 seconds) resulting in Wolf Creek experiencing a LOOP condition. Emergency Diesel Generators A and B automatically started and powered their respective safety buses approximately eight seconds after the start of the event. At 2:15 p.m., the shift manager declared a Notification of Unusual Event based on the expectation that the LOOP would last longer than 15 minutes. At 4:45 p.m.,

the 345 kV East Bus was reenergized from the La Cygne line by closing Breaker 345-120, restoring offsite power to the Train A safety-related components (Bus NB01). At 5:09 p.m., the Notification of Unusual Event was terminated.

On January 15th, operators restored offsite power to Bus NB02 by closing the Alternate Feeder Breaker NB0212 to power Train B from Train A once in Mode 5 and EDG B was secured.

Electrical repairs were not completed until February 4th, when the SUT was returned to service and damaged wires and a bus potential transformer for Breakers PA0201 and PA0110 were replaced and the breakers were returned to service. See References 1-3 for further details.

Sequence of Key Events. The following table provides a sequence of key events:

January 13, 2012 The plant is at one hundred percent rated thermal power, with no plant evolutions in progress, transmission switching, or adverse weather

LER 482/12-001 2

conditions; pressurizer PORV Block Valve BB-8000A is closed due to PCV-455A leakage.

14:02 Main Generator Output Breaker 345-60 on Phase C develops a fault leading to a main generator transformer lockout. East Bus 345-120 Breakers 345-120, 345-90, and 345-60 open; therefore, de-energizing the 345 kV East Bus. A Unit Trip Signal is received; the main turbine trips.

Main Generator Output Breaker 345-50 breaker opens and Transformer No. 7 Breaker 13-48opens, removing power to Train A Safety Bus. Fast bus transfer of non-vital buses from UAT to SUT begins, Breakers PA0211 and PA0101 open, and Breakers PA0202 and PA0110 Close completing the fast transfer. SUT protective relay trips on Phase B differential causing 345 kV West Bus differential lockout. West Bus Breakers 345-40, 345-110, and 345-70 open; therefore, de-energizing the 345 kV West Bus. Breakers PA0202, PA0110, PA0201 open isolating the SUT from the Train B Safety Bus. Reactor Main Trip Breaker B opens and the reactor trips due to turbine trip and reactor power greater than 50 percent. The plant is in Mode 3. Breakers NB0112 and NB0209 open, therefore, offsite power is completely disconnected from both safety buses. Instrument air pressure starts to decrease due to loss of power to the air compressors. Letdown isolates due to loss of power. SG atmospheric dump valve (ADV) A opens.