ML100330574

IR 05000482-09-007 on 09/21/09 - 12/4/09 for Wolf Creek; Special Inspection in Response to Loss of Offsite Power and Essential Service Water Leak on August 19, 2009

ML100330574
Person / Time
Site:	Wolf Creek
Issue date:	02/02/2010
From:	Chamberlain D NRC/RGN-IV/DRP
To:	Matthew Sunseri Wolf Creek
References
IR-09-007
Download: ML100330574 (55)

See also: IR 05000482/2009007

Text

UNITED STATES

NUCLEAR RE GULATO RY COM M I SSI ON

R EGI ON I V

612 EAST LAMAR BLVD, SUI TE 400

ARLIN GTON, TEXAS 76011-4125

February 2, 2010

Matthew W. Sunseri, President and

Chief Executive Officer

Wolf Creek Nuclear Operating Corporation

P. O. Box 411

Burlington, KS 66839

Subject: WOLF CREEK GENERATING STATION - NRC SPECIAL INSPECTION

REPORT 05000482/2009007

Dear Mr. Sunseri:

On December 4, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed a special

inspection at your Wolf Creek Generating Station. This inspection examined activities

associated with the stations performance during a loss of offsite power on August 19, 2009.

The NRCs initial evaluation of this issue, using the criteria in NRC Management Directive 8.3,

NRC Incident Investigation Program, determined that the estimated Incremental Conditional

Core Damage Probability was 6.1 x 10-6. This guided the NRC to charter and conduct a special

inspection.

The enclosed report documents the inspection results, which were discussed at the exit meeting

on December 22, 2009, with you and other members of your staff. The inspection examined

activities conducted under your license as they relate to safety and compliance with the

Commissions rules and regulations and with the conditions of your license. The inspection

team reviewed selected procedures and records, observed activities, and interviewed

personnel.

This report documents seven NRC-identified and self-revealing findings of very low safety

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

requirements. Additionally, one licensee-identified violation, which was determined to be of very

low safety significance, is listed in this report. However, because of their very low safety

significance and because they are entered into your corrective action program, the NRC is

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

Enforcement Policy. If you contest the noncited violations in this report, you should provide a

response within 30 days of the date of this inspection report, with the basis for your denial, to

the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,

Washington, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear

Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington,

Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,

Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Wolf Creek Generating

Station. In addition, if you disagree with the characterization of any finding in this report, you

should provide a response within 30 days of the date of this inspection report, with the basis for

your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector

Wolf Creek Nuclear Operating Corp. -2-

at the Wolf Creek Generating Station. The information you provide will be considered in

accordance with Inspection Manual Chapter 0305.

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

enclosure, will be available electronically for public inspection in the NRC Public Document

Room or from the Publicly Available Records component of NRCs document system (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the

Public Electronic Reading Room).

Sincerely,

/RA/ A. Vegel for

Dwight D. Chamberlain, Director

Division of Reactor Projects

Docket: 50-482

Licenses: NPF-42

Enclosure: NRC Inspection Report 05000482/2009007

w/Attachments: Supplemental Information

Charter

NRC Technical Review of the August 19, 2009, Self-Revealing Flaw in

Essential Service Water System Piping

cc w/Enclosure:

Vice President Operations/Plant Manager

Wolf Creek Nuclear Operating Corporation

P.O. Box 411

Burlington, KS 66839

Jay Silberg, Esq.

Pillsbury Winthrop Shaw Pittman LLP

2300 N Street, NW

Washington, DC 20037

Supervisor Licensing

Wolf Creek Nuclear Operating Corporation

P.O. Box 411

Burlington, KS 66839

Chief Engineer

Utilities Division

Kansas Corporation Commission

1500 SW Arrowhead Road

Topeka, KS 66604-4027

Office of the Governor

State of Kansas

Topeka, KS 66612-1590

Wolf Creek Nuclear Operating Corp. -3-

Attorney General

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

Topeka, KS 66612-1597

County Clerk

Coffey County Courthouse

110 South 6th Street

Burlington, KS 66839

Chief, Radiation and Asbestos

Control Section

Bureau of Air and Radiation

Kansas Department of Health and

Environment

1000 SW Jackson, Suite 310

Topeka, KS 66612-1366

Chief, Technological Hazards

Branch

FEMA, Region VII

9221 Ward Parkway

Suite 300

Kansas City, MO 64114-3372

Wolf Creek Nuclear Operating Corp. -4-

Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

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

DRP Director (Dwight.Chamberlain@nrc.gov)

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

DRS Director (Roy.Caniano@nrc.gov)

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

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

Resident Inspector (Charles.Peabody@nrc.gov)

Site Secretary (Shirley.Allen@nrc.gov)

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

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

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

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

Branch Chief, DRS/TSB (Michael.Hay@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

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

OEMail Resource

ROPreports

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

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

File located: R:\_REACTORS\_WC\2009\WC 2009007RWD.doc ML#100330574

ADAMS: No  : Yes SUNSI Review Complete Reviewer Initials: RWD

Publicly Available  : Non-Sensitive

Category A. Non-Publicly Available Sensitive

KEYWORD:

C:DRP/B SPE:DRP/B SRI:DRP/B RI:DRP:/B

GMiller RDeese DDumbacher GTutak

/RA/ /RA/ /RA/ via e-mail /RA/ via e-mail

1/31/10 1/28/10 1/26/10 1/26/10

SME/HQ RI:DRP/B

JMedoff CLong

/RA/ via e-mail /RA/

1/19/10 1/26/10

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

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 50-482

License: NPF-42

Report: 05000482/2009007

Licensee: Wolf Creek Nuclear Operating Corporation

Facility: Wolf Creek Generating Station

Location: 1550 Oxen Lane SE

Burlington, Kansas

Dates: September 21 through December 4, 2009

Inspectors: R. Deese, Senior Project Engineer

D. Dumbacher, Senior Resident Inspector, Callaway Plant

G. Tutak, Reactor Inspector

J. Medoff, Senior Mechanical Engineer

M. Runyan, Senior Reactor Analyst

C. Long, Senior Resident Inspector, Wolf Creek Generating Station

C. Peabody, Resident Inspector, Wolf Creek Generating Station

Approved By: G. Miller, Chief, Project Branch B, Division of Reactor Projects

1 Enclosure

SUMMARY OF FINDINGS

IR 05000482/2009007; 09/21/09 through 12/4/09; Wolf Creek Generating Station, Special

Inspection in response to the loss of offsite power and essential service water leak on

August 19, 2009.

This report covered a 5-day period (September 21-25, 2009) of onsite inspection, with in office

review through December 4, 2009. This special inspection was conducted by a senior project

engineer, a senior resident inspector, a reactor inspector, a headquarters specialist, and a

senior reactor analyst assisted by a senior resident inspector and a resident inspector. Six

Green noncited violations and one Green finding of significance were identified. The

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

NRC Inspection Manual Chapter 0609, "Significance Determination Process." Findings for

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

severity level after NRC management review. The NRC's program for overseeing the safe

operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor

Oversight Process," Revision 4, dated December 2006.

A. NRC-Identified Findings and Self-Revealing Findings

Cornerstone: Initiating Events

• Green. The team identified a finding associated with the licensees failure to

recognize the adverse conditions related to their offsite power system as

prescribed by Procedure AP 28A-100, Condition Reports. Specifically, the

licensee failed to enter pertinent switchyard operating experience and six

occurrences of offsite power line losses as adverse conditions in their corrective

action program as of August 2009. The licensee entered these deficiencies in

their corrective action program as Wolf Creek Condition Reports 00022242

and 00022241.

This finding is greater than minor because, if left uncorrected, the failure to fully

utilize the corrective action program could become a more significant safety

concern. The inspectors determined that this finding impacted the Initiating

Events Cornerstone equipment maintenance attribute and affected the

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

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

operations. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and

Characterization of Findings, the issue screened as having very low safety

significance because it did not contribute to both the likelihood of a reactor trip

and the likelihood that mitigation equipment or functions would not be available

(Section 1R2).

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

Specification 5.4.1.a, Procedures, after operators failure to monitor and

maintain steam generator water levels resulted in an unanticipated turbine trip

signal and feedwater isolation. On August 21, 2009, while in Mode 3, Wolf Creek

operators, using an intermittent method of feeding steam generators over shift

turnover, lost control of the level in steam generator A. This resulted in increased

levels above the P-14 feedwater isolation actuation setpoint. Contributing to the

loss of level control was the disabling of a previously established operator

2 Enclosure

selectable alarm for the steam generator level. The licensee entered this

deficiency in their corrective action program as Wolf Creek Condition

Report 00019295.

This finding is greater than minor because it impacted the Initiating Events

Cornerstone human performance attribute and affected the cornerstone objective

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

critical safety functions during shutdown as well as power operations. Using

Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of

Findings, the issue screened as having very low safety significance because it

did not contribute to both the likelihood of a reactor trip and the likelihood that

mitigation equipment or functions would not be available and it did not increase

the likelihood of a fire or internal/external flooding. This finding has a

crosscutting aspect in the area of human performance associated with the

decision making component because licensee personnel failed to make safety-

significant or risk-significant decisions using a systematic process especially

when faced with uncertain or unexpected plant conditions to ensure that safety is

maintained H.1(a) (Section 1R7).

Cornerstone: Mitigating Systems

• Green. The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, regarding the licensees

failure to follow the requirements of Procedure AP 26C-004, Technical

Specification Operability. Specifically, licensee personnel failed to perform an

operability evaluation for the impact of the 2009 pressure transient and internal

corrosion on the essential service water system. The Wolf Creek essential

service water system was degraded by a system pressure transient on August

19, 2009. Also in 2009, widespread internal corrosion resulted in at least three

through wall leaks. Discovery of these conditions had been documented in the

corrective action program but had not resulted in performance of an operability

evaluation of the current and potentially future impact on the system as a whole.

The licensee entered this deficiency in their corrective action program as Wolf

Creek Condition Report 00022240.

This finding is greater than minor because it is associated with the Mitigating

Systems Cornerstone attribute of equipment performance and adversely affected

the objective to ensure equipment availability and reliability. Using Manual

Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings,

the issue screened as having very low safety significance because it was not a

design or qualification deficiency that resulted in a loss of operability or

functionality, did not create a loss of system safety function of a single train for

greater than the technical specification allowed outage times, and did not affect

seismic, flooding, or severe weather initiating events. This finding has a

crosscutting aspect in the area of problem identification and resolution

associated with the corrective action program because licensee personnel failed

to thoroughly evaluate problems such that the resolutions address causes and

extent of conditions P.1(c) (Section 1R2).

• Green. The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, regarding the licensees

3 Enclosure

failure to follow the requirements of Procedure AI 28A-010, Screening Condition

Reports. Specifically, licensee personnel failed to properly screen condition

reports for the essential service water system adverse conditions of internal

corrosion and loss of offsite power induced system pressure transient since

April 2008. The adverse conditions met the procedures definitions to require a

root cause analysis prior to September 2009, but none was performed. The

licensee entered this deficiency in their corrective action program as Wolf Creek

Condition Report 00022239.

This finding is greater than minor because, if left uncorrected, the failure to fully

utilize the corrective action program could become a more significant safety

concern. The inspectors determined that this finding impacted the Mitigating

Systems Cornerstone. Using Manual Chapter 0609.04, Phase 1 - Initial

Screening and Characterization of Findings, the issue screened as having very

low safety significance because it was not a design or qualification deficiency that

resulted in a loss of operability or functionality, did not create a loss of system

safety function of a single train for greater than the technical specification allowed

outage times, and did not affect seismic, flooding, or severe weather initiating

events. This finding has a crosscutting aspect in the area of problem

identification and resolution associated with the corrective action program

because licensee personnel failed to thoroughly evaluate problems such that the

resolutions address causes and extent of conditions P.1(c) (Section 1R2).

• Green. The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, regarding the licensees

failure to provide adequate guidance to identify and address pitting, corrosion,

and surface indications in the essential service water system. A 2007 licensee

self-assessment on lake water corrosion issues recommended improvements in

lake water chemistry control procedures to establish a pit monitoring program. In

September 2009 NRC inspectors noted that the lake water monitoring and

chemistry control procedures did not contain quality standards or acceptance

criteria for newly discovered flaws or abnormal gross degradation due to erosion,

pitting, or corrosion. This resulted in delaying repairs until such degradations

(pitting) had become through-wall leaks. Several instances of internally identified

corrosion were not entered into the corrective action program until essential

service water piping had thinned to below the minimum ASME code allowed wall

thickness. The licensee entered this deficiency in their corrective action program

as Wolf Creek Condition Report 00022243.

This finding is greater than minor because it is associated with the Mitigating

Systems Cornerstone attribute of procedure quality and adversely affected the

objective to ensure equipment availability and reliability. Using Manual

Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings,

the issue screened as having very low safety significance because it was not a

design or qualification deficiency that resulted in a loss of operability or

functionality, did not create a loss of system safety function of a single train for

greater than the technical specification allowed outage times, and did not affect

seismic, flooding, or severe weather initiating events. This finding has a

crosscutting aspect in the area of problem identification and resolution

associated with the corrective action program because licensee personnel failed

4 Enclosure

to take appropriate corrective actions to address safety issues and adverse

trends in a timely manner P.1(d) (Section 1R4).

• Green. The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, regarding the licensees

failure to provide adequate guidance to address the impact of a loss of offsite

power event on the essential service water system. On August 19, 2009, seven

hours following a loss of offsite power, the NRC senior resident identified leakage

from the piping on the 1988 elevation of the auxiliary building. Wolf Creek

Procedure STN PE-040G, Transient Event Walkdown, required that systems

subject to expected transient dynamic forces following a reactor trip to have a

post-trip walkdown to identify any structural damage. This procedure did not

include the essential service water system as a vulnerable system. The

procedure only specifically identified portions of systems inside containment. As

a result, no walkdown was performed for the essential service water system on

August 19, 2009. The licensee entered this deficiency in their corrective action

program as Wolf Creek Condition Report 00022265.

This finding is greater than minor because it is associated with the Mitigating

Systems Cornerstone attribute of procedure quality and adversely affected the

objective to ensure equipment availability and reliability. Using Manual

Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings,

the issue screened as having very low safety significance because it was not a

design or qualification deficiency that resulted in a loss of operability or

functionality, did not create a loss of system safety function of a single train for

greater than the technical specification allowed outage times, and did not affect

seismic, flooding, or severe weather initiating events. This finding has a

crosscutting aspect in the area of problem identification and resolution

associated with the operating experience component because the licensee failed

to institutionalize lessons learned through changes to station walkdown

procedures P.2(b) (Section 1R5).

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

Fire Protection, for the failure to establish a compensatory fire watch in a timely

manner per the station fire protection program. On August 19, 2009, a complete

loss of offsite power resulted in fire protection trouble alarms on fire protection

panel KC-008. The control room supervisor acknowledged the alarms.

Procedure ALR KC-888, Fire Protection Panel KC-008 Alarm Response,

required an impairment and compensatory measures for the affected smoke

detectors. The following day, NRC inspectors noted that impairments and fire

watches for the 13 affected fire zones on KC-008 had not been initiated. The

licensee entered this deficiency in their corrective action program as Wolf Creek

Condition Report 00019320.

This finding was more than minor since it was associated with the protection

against external factors attribute of the Mitigating Systems Cornerstone and

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

and capability of systems that respond to initiating events to prevent undesirable

consequences. Using Manual Chapter 0609, Appendix F, Fire Protection

Significance Determination Process, the inspectors determined that the finding

had an adverse affect on the fixed fire protection systems element of fixed fire

5 Enclosure

detection systems. This finding was determined by a senior reactor analyst to be

of very low safety significance because of a low exposure time of the

uncompensated deficiency. This finding has a crosscutting aspect in the area of

human performance associated with the work practices component because the

licensee failed to ensure supervisory oversight of work activities such that

nuclear safety is supported H.4(c) (Section 1R5).

B. Licensee-Identified Violations

One violation of very low safety significance, which was identified by the licensee, was

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

been entered into the licensees corrective action program. This violation and its

condition report number are listed in Section 4OA7.

6 Enclosure

REPORT DETAILS

1. REACTOR SAFETY

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

Preparedness

1R0 Introduction

On August 19, 2009, the NRC determined that a special inspection was warranted, in

part, based on the potential safety significance of a complete loss of offsite power and

because of potential generic issues associated with essential service water design and

internal corrosion.

The inspection charter required the team to: (1) review the circumstances related to the

discovery of the degraded conditions, (2) assess the licensees determination of cause

and effectiveness of actions taken to resolve and prevent recurrence of these problems,

and (3) assess the effectiveness of licensee programs to maintain the physical condition

of the offsite power systems and the essential service water system. The team

evaluated the licensee actions to address these issues including extent of condition,

extent of cause, and common cause questions. Specific focus was on licensee

response to prior instances of loss of the offsite power lines and assessment of

implementation of general design criteria requirements for independence of the offsite

power lines. The inspectors reviewed the licensees Generic Letter 89-13, Service

Water System Problems Affecting Safety-Related Equipment, program to ensure

appropriate testing was being performed that would demonstrate essential service water

system ability to function under design-basis conditions.

The team conducted their reviews in accordance with NRC Inspection Procedure 93812,

Special Inspection Procedure. The special inspection team reviewed procedures,

corrective action documents, as well as design and maintenance records for the

equipment of concern. The team interviewed key station personnel regarding the

events, reviewed the root cause analysis, and assessed the adequacy of corrective

actions. The team walked down and inspected the equipment in the field. A list of

specific documents reviewed is provided as Attachment 1. The charter for the special

inspection is provided as Attachment 2.

1R1 Sequence of Events Related to the Event

On August 19, 2009, Wolf Creek Generating Station experienced a complete loss of

offsite power to the two essential 4 kV bus transformers, XNB01 and XNB02, for about

49 seconds. This condition resulted from a lightning strike causing a fault four miles to

the east of the plant on the tie-line to La Cygne 345 kV substation. Wave trap and

tuning circuitry damage caused carrier system signal failures which prevented the feeder

breakers from two other substations, Rose Hill and Benton, from getting block signals.

Thus, these substation feeds were also rendered unavailable to Wolf Creek. The Wolf

Creek main generator experienced a load change from approximately 1220 MW to

100 MW. This resulted in a turbine trip - reactor trip. All reactor coolant pump motors

tripped on underfrequency. The main generator protection lockout relay 386-2G

actuated, opening the main generator output breakers. At 49.6 seconds after the

initiating event, the feeder breakers to 4 kV busses NB01 and NB02 were tripped open

7 Enclosure

by loss of voltage relays. At 55.2 seconds after the initiating event, the transmission

system operator closed the Wolf Creek - Rose Hill transmission network line

breaker 345-50. This restored one transmission line, supporting offsite power to Wolf

Creeks essential 4 kV bus transformers. At 56.5 seconds, the emergency diesel

generator output breakers NE001 and NE002 closed onto safety related 4 kV busses

NB01 and NB02. At 12 minutes, the Wolf Creek - Benton 345 kV network line

breaker 345-120 was closed by the transmission operator, restoring a second

transmission line supporting offsite power. At 13 minutes and 6 seconds, the

transmission system operator restored the third transmission line. One hour and

50 minutes after the event, offsite power was restored to safety related bus NB02.

Two hours and 54 minutes after the event, offsite power was restored to safety related

bus NB01.

This was the second loss of offsite power event at Wolf Creek in less than 18 months.

The first occurred on April 7, 2008, during a refueling outage. For both of the loss of

offsite power events, damage requiring repairs occurred within the essential service

water system. In this event, a 3/8-inch hole developed in the licensees service water

system.

1R2 Review of Problem Identification and Resolution Aspects of the Event

.1 Review of Operating Experience

a. Licensee Review of Operating Experience

Responsibility for most of the switchyard work rested with Westar Energy. As a result,

Wolf Creek typically did not enter switchyard-related maintenance and industry operating

experience into the corrective action program. Wolf Creek only entered external

operating experience evaluations into the corrective action program. Wolf Creek

received external operating experience, but did not effectively communicate the grid and

switchyard recommendations to Westar Energy.

Wolf Creek completed Self-Assessment 05-001, Transformer and Switchyard Self-

Assessment, in March 2005, to evaluate the interface of the nuclear power plant and

the switchyard in terms of maintenance, operation, design, and performance monitoring

relative to large power transformers and switchyard equipment. Wolf Creek also

evaluated Westars control of the grid as it affects the nuclear plant in terms of stability of

offsite power. Wolf Creek also reviewed transmission line design and grid voltage

control.

The licensees incident investigation team reviewed over 30 condition reports that were

generated from self-assessments and other industry operating experience. Based on

their review, the licensee team concluded that the performance improvement programs,

such as the Corrective Action Program, were not being used or implemented effectively.

Improper screening of condition reports had not allowed Wolf Creek to adequately

describe and evaluate problems.

b. Inspection Scope

The team reviewed internal operating experience by obtaining a list of plant corrective

action documents related to the offsite power and essential service water system. The

8 Enclosure

team further examined the licensees review of industry operating experience which

included inspection of the licensees operating experience program and specific review

of related condition reports for the August 19, 2009, event.

For external operating experience, the NRC Operating Experience Branch provided the

results of keyword searches related to offsite power and essential service water issues

and findings associated with essential service water leaks. The NRC Operating

Experience Branch also provided a list of licensee event reports, NRC Information

Notices, NUREG documents, and other operating experience information. The team

selected operating experience information that was applicable to this inspection and

reviewed how the licensee had addressed the items in their root cause analyses related

to these events or had processed the information through their operating experience

program. As part of their review, the inspectors performed an essential service water

system walkdown to determine if applicable industry operating experience had been

incorporated into system design and maintenance practices.

c. Findings

No findings of significance were identified.

.2 Review of Root Cause Analysis

a. Licensee Review

Incident Investigation Team

On August 20, 2009, the licensee established an incident investigation team to perform a

root cause analysis to investigate the facts and identify the causes of the loss of offsite

power and subsequent plant trip on August 19, 2009. The licensees final root cause

analysis was completed on October 1, 2009. The team consisted of site personnel,

Westar staff, and industry experts. The team conducted their review in accordance with

Procedure AI 28A-001, Level 1 CR Evaluation (IIT). The incident investigation teams

objectives were to:

• Determine the sequence of events

• Assess the risk and safety-significance of the event

• Identify and validate root and contributing causes

• Conduct an extent of condition review

• Determine extent of cause

• Develop corrective actions to limit likelihood of recurrence

• Evaluate existing procedures and processes

• Determine why prior corrective actions and applicable operating experience were

not effective in preventing the event.

9 Enclosure

Licensee Root Cause Methodology

The licensee performed their analysis utilizing a structured root cause analysis method

in accordance with Procedures AI 28A-001, Level 1 CR Evaluation (IIT), and

AI 28A-016, Cause Analysis Methods and Techniques. The licensee interviewed plant

personnel and reviewed condition reports, procedures, and other important documents

to perform the root cause analysis. The licensee created a detailed event and causal

factors chart to establish the sequence of events and provide a complete view of the

causes and contributors to the incident. The licensee used fault tree analysis, change

analysis, common cause analysis, hardware failure analysis, and hazard-barrier-target

analysis to supplement the investigation. The licensee also completed a management

oversight and risk tree analysis and an event cause and effect diagram to complete the

investigation.

Licensee Root Cause Analysis

The licensee determined that the root cause of the event was that Wolf Creek and the

transmission and distribution organization have not sufficiently ensured a mutually

desired level of reliable service for substation and transmission interfacing equipment

with Wolf Creek.

The licensee determined that the following issues contributed to the event:

• Westar Energys transmission line and substation design/maintenance had not

always applied updated electric utility industry practices to ensure the desired

level of reliable service for the applicable substations and transmission systems.

• A reliability-centered maintenance program was in progress for Wolf Creek

Generating Station, but not fully implemented for the Wolf Creek Substation.

Reliability-centered maintenance for the remote substation terminals and

transmission preventive maintenance, inspection, and testing had not been

effectively developed or implemented to the point equipment reliability meets

expectations.

• Relevant operating experience for substation and transmission systems had not

been effectively reviewed or utilized by Wolf Creek and shared with the

transmission and distribution organization.

• A process did not exist between Wolf Creek and the transmission and distribution

organization to effectively coordinate corrective action evaluations, action

tracking, and priorities.

b. Inspection Scope

The team reviewed the licensees root cause analysis prepared for the loss of offsite

power event. The team membership, team charter, report methodology, root and

contributing causes, recommended corrective actions, and supporting documentation

were reviewed. The team interviewed personnel who participated in the root cause

determination as well as personnel who were charged to implement corrective actions of

the report.

10 Enclosure

c. Findings

No findings of significance were identified.

.3 Review of Licensee Corrective Actions

a. Licensee Review

Licensee Review of Extent of Condition

The licensee determined the extent of condition to be the area of owner-controlled

equipment that was not previously fully considered to be within the scope of equipment

needing life cycle management and maintenance strategies in response to prior industry

operating experience. This equipment includes transformers or other communications

equipment in the carrier system, including wave traps, lightning arrestors, cabling, relays

and protection schemes, switches, disconnects, breakers, tuners, and surge arrestors.

The entire 345 kV switchyard and transmission system were included in the extent of

condition review. This equipment has the potential to adversely impact Wolf Creek and

offsite power source operation and reliability. The licensee factored the extent of

condition into all of the corrective actions planned in response to the loss of offsite power

event.

Licensee Corrective Actions

The existing equipment vulnerability was resolved by actions taken to replace all three

Rose Hill substation coupling capacitor voltage transformers, walk down the Rose Hill

and Wolf Creek substations, and test the carrier system for the three transmission lines

providing offsite power to Wolf Creek.

b. Inspection Scope

The team reviewed the licensees root cause analysis to determine if it was conducted to

a level of detail commensurate with the significance of the problem. As part of their

review, the inspectors interviewed key station personnel from operations, design and

system engineering, maintenance, and the corrective action program. Additionally, the

team interviewed incident investigation team members and members of the licensees

Corrective Action Review Board.

The team reviewed the licensees corrective actions to ensure they addressed the extent

of condition and whether they were adequate to prevent recurrence. In particular, the

team reviewed station procedures and processes to determine if any other issues exist

within Wolf Creeks offsite power system or essential service water system.

c. Findings and Observations

Root Cause Analysis

The inspectors determined that the licensees analysis accurately captured the root

cause of the offsite power event. Since the event was determined to be caused by

improper oversight of the switchyard between Wolf Creek and Westar, the inspectors

noted that the licensee appropriately identified a need to implement several corrective

actions related to improving the understanding of the importance of a reliable offsite

11 Enclosure

power system. The inspectors concluded the corrective actions were appropriate. The

inspectors noted that there was not a similar corresponding analysis or effort by the

licensee regarding leakage from the essential service water system following the loss of

offsite power event.

1. Entry of Conditions into the Corrective Action Program

Introduction. The team identified a Green finding regarding the licensees failure to

follow the requirements of Procedure AP 28A-100, Condition Reports, associated with

failure to recognize adverse conditions with respect to the corrective action program.

Description. On August 19, 2009, a complete loss of offsite power resulted in a reactor

trip. A fault was detected on the La Cygne 345 kV transmission line causing breakers in

the Wolf Creek switchyard to open. However, the carrier communications equipment

failed to block the trip signal on the Rose Hill 345 kV transmission line. The line

deenergized, and the resulting grid instability caused the Benton 345 kV transmission

line to trip, which resulted in a loss of offsite power to Wolf Creek. The carrier

communications equipment did not function as required due to the failure of a coupling

capacitor voltage transformer in the Rose Hill substation. The licensee had received

industry operating experience related to switchyard equipment and its importance to

maintaining a reliable grid, but failed to recognize the significance of switchyard reliability

as evidenced by their failure to effectively screen relevant industry operating experience.

In particular, Condition Report 00007499 was created from a third party recommendation

to develop a monitoring program for coupling capacitor voltage transformers in the

switchyard. This condition report, along with several other switchyard-related condition

reports, were screened to Improvement and Learning Evaluation, which is the lowest

level in the licensees condition reporting system.

The licensee did not take action on several switchyard-related condition reports since

due dates are not typically assigned for implementation of corrective actions for

Improvement and Learning Evaluation condition reports. In Attachment B of

Procedure AP 28A-100, the licensee defines adverse conditions, in part, as conditions

that could negatively impact plant reliability and includes industry operating experience

that is applicable or relevant to Wolf Creek as an example. The inspectors determined

that the licensee had not properly recognized these conditions as adverse conditions.

Also, the team learned that the licensees incident investigation team had determined

that offsite power had numerous interruptions in the past. In their charter, the team was

instructed to inspect previous line losses because regional inspectors noted that the

station had experienced a high number of offsite power interruptions in the recent past.

Based on this observation, the team requested information relating to previous line

losses and learned that since 2004, there had been 31 instances of offsite power

interruptions of at least one line. The team licensee staff had been done in these

instances. The team learned that the cognizant engineer had kept a spreadsheet of all

of these instances and what actions had been taken. The team noted that only 25 of

these instances had been entered into the corrective action program.

Section 2.1 of Procedure AP 28A-100 states that this procedure applies to adverse

conditions that affect equipment, procedures, or personnel and conditions deemed to be

undesirable or questionable. From this, the team concluded that offsite power line

interruptions affecting the availability of offsite power were an adverse condition that

12 Enclosure

affected plant equipment that was undesirable, or at least questionable, and within the

scope of Procedure AP 28A-100.

Section 6.1 of Procedure AP 28A-100 details the licensees guidance for recognizing an

adverse condition. Within this section, Step 6.1.1 instructs Wolf Creek personnel to

initiate a condition report document when they recognize an adverse condition.

Substep 1 of Step 6.1.3 of Procedure AP 28A-100 gives examples of some adverse

conditions. These include:

Step 1.b. A plant or system transient

Step 1.c. An unanticipated actuation or reposition of equipment

The team concluded that offsite power line interruptions comprised an offsite power

system transient. They also concluded that offsite power line interruptions comprised

unanticipated repositioning of equipment.

Based on these conclusions, the team determined that the licensee should have

recognized these conditions as adverse conditions and as a result entered them into

their corrective action program.

The team also observed that all line losses since August 2008 were entered into the

corrective action program. From this, the team concluded that the failure to enter

adverse conditions in the corrective action problem was being addressed by the

licensees ongoing problem identification and resolution improvement initiative and was

not indicative of current performance.

Analysis. The performance deficiency associated with this finding involved the

licensees failure to follow the requirements of Wolf Creek Procedure AP 28A-100.

Specifically, licensee personnel failed to recognize adverse conditions with respect to

the corrective action program which affected the reliability of the offsite power system.

This finding is greater than minor because if left uncorrected, the failure to fully utilize the

corrective action program could become a more significant safety concern. This finding

was more than minor because it impacted the equipment performance attribute of the

Initiating Events Cornerstone objective to limit the likelihood of those events that upset

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

operations. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and

Characterization of Findings, the inspectors determined that the finding was of very low

safety significance (Green) because it did not contribute to both the likelihood of a

reactor trip and the likelihood that mitigation equipment or functions would not be

available. A crosscutting aspect was not identified for this finding because the

inspectors concluded the deficiency in this area was not indicative of current

performance.

Enforcement. The performance deficiency did not involve a violation of regulatory

requirements because the offsite power sources feeding the Wolf Creek switchyard are

not safety-related. The licensee entered this issue into their corrective action program

as Condition Reports 00022241 and 00022242. Because this finding does not involve a

violation of regulatory requirements and has very low safety significance, it is identified

as FIN 05000482/2009007-01, Failure to Enter Adverse Conditions into the Corrective

Action Program.

13 Enclosure

2. Handling and Evaluation of Noted Conditions

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

Appendix B, Criterion V, Instructions, Procedures, and Drawings, regarding the

licensees failure to follow the requirements of Procedures AP 28-001, Operability

Evaluations, and AP 26C-004, Technical Specification Operability, associated with

deficiencies resulting from the loss of offsite power induced pressure transient on the

essential service water system. The pressure transient resulted in significant leakage

from the system and required immediate repair.

Description. When the essential service water pumps started following the loss of offsite

power event on August 19, 2009, the resulting pressure surge (water hammer) created

forces that contributed to a three-eighths inch diameter circular hole in essential service

water piping on the 1988 elevation of the auxiliary building. No operability evaluation

was performed immediately following the August 19, 2009, event. Additionally, the

licensee discovered multiple examples of through-wall leakage and essential service

water piping wall thinning attributed to internal corrosion in the summer of 2009. In

April 2008, a loss of offsite power had created a water hammer on the essential service

water system piping resulting in leakage from control room air conditioner and

emergency diesel generator heat exchangers. The air conditioning unit heat exchanger

experienced sufficient forces to stretch the heat exchanger end bell bolting. In

Operability Evaluation GK-08-004, the licensee determined that the piping and heat

exchanger repairs were sufficient to assure continued functionality of the essential

service water system. Operability Evaluation GK-08-004 did not evaluate the essential

service water system as a whole to provide a documented basis for continued

functionality after the water hammer event.

Wolf Creek Procedure AP 26C-004 required that an operability determination be

performed immediately upon determination that a deficiency exists that could affect the

operability of an SSC subject to Technical Specifications. In Step 4.1.1 the procedure

defined deficiency as an all-inclusive term used in reference to any condition or

circumstance that reduces the confidence that a structure, system, or component (SSC)

will perform satisfactorily in service. The August 19, 2009, water hammer was not

discussed in any corrective action document until September 23, 2009, when the NRC

questioned the basis for continued operability of the system. During this inspection on

September 24, 2009, the licensee initiated Operability Evaluation EF 09-007. This

evaluation noted that the essential service water system safety design basis as

described in Updated Safety Analysis Report 9.2.1.2.1.1 defined, in part, the following

system required functions:

• Safety Design Basis Three - Safety functions can be performed assuming a

single active component failure coincident with the loss of offsite power (GDC 44)

• Safety Design Basis Eleven - The essential service water system is protected

from long term organic fouling and corrosion problems

Operability Evaluation EF 09-007 indicated that most of the essential service water

system piping and valves are carbon steel and susceptible to internal localized

corrosion. Wolf Creek relies on internal inspection of the essential service water piping

whenever components within the system are removed for work. As noted above,

several recent piping failures have occurred indicating an increased trend in degradation

14 Enclosure

of the piping wall thickness. There was no operability evaluation for the internal

corrosion until prompting by NRC team inspectors.

The September 24, 2009, operability evaluation concluded that any subsequent

corrosion causing piping leakage would be limited to essential service water flow losses

less than or equal to those that have already occurred, and thus be bounded by the

maximum allowable essential service water leakage (140 gpm) from the ultimate heat

sink system. To address the possible future essential service water system water

hammer events, the licensee is pursuing an engineered solution from a contracted

engineering firm. The licensee is planning increased nondestructive inspection using

ultrasonic detection of degraded wall thickness to determine the extent of condition.

Analysis. The performance deficiency associated with this finding involved the

licensees failure to perform an adequate operability evaluation for the essential service

water system identified nonconforming conditions related to repeated occurrences of

system water hammer and localized internal corrosion. This finding is more than minor

because it is associated with the Mitigating Systems Cornerstone attribute of equipment

performance and adversely affects the objective to ensure equipment availability and

reliability. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and

Characterization of Findings, the issue screened as having very low safety significance

because it was not a design or qualification deficiency that resulted in a loss of

operability or functionality, did not create a loss of system safety function of a single train

for greater than the technical specification allowed outage times, and did not affect

seismic, flooding, or severe weather initiating events. This finding has a crosscutting

aspect associated with the problem identification and resolution area component of the

corrective action program because licensee personnel failed to thoroughly evaluate

problems such that the resolutions address all causal factors and extent of conditions, as

necessary P.1(c).

Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities

affecting quality shall be prescribed by documented instructions or drawings of a type

appropriate to the circumstances and shall be accomplished in accordance with these

instructions or drawings. Contrary to the above, following a water hammer event and

essential service water system pressure boundary leakage in 2009, the licensee failed to

use the operability process immediately upon determination that a deficiency existed that

could have affected the operability of the essential service water system as required by

Step 6.1.4 of Procedure AP 26C-004, Technical Specification Operability. Specifically,

the licensee failed to perform Step 6.1.6 of Procedure AP 26C-004, which calls for

performance of an immediate operability determination. Because of the very low safety

significance and Wolf Creeks action to place this issue in their corrective action program

as Condition Report 00022240, this violation is being treated as a noncited violation in

accordance with Section VI.A.1 of the Enforcement Policy: NCV 05000482/2009007-02,

Failure to Perform an Operability Evaluation.

3. Screening of Conditions in the Corrective Action Program

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

Appendix B, Criterion V, Instructions, Procedures, and Drawings, regarding the

licensees failure to follow the requirements of Procedure AI 28A-010, Screening

15 Enclosure

Condition Reports, Revision 3A, associated with the effects of a loss of offsite power

induced water hammer of the essential service water system.

Description. On August 19, 2009, a complete loss of offsite power resulted in a water

hammer of the essential service water system which created forces that contributed to a

three-eighths inch diameter circular hole in essential service water piping on the

1988 elevation of the auxiliary building. In June and July of 2009, the licensee identified

that internal corrosion had created through-wall leakage on the 1974 elevation essential

service water piping. In April 2008 a similar loss of offsite power created a water

hammer of the essential service water piping. This occurrence created leakage from

control room air conditioner and emergency diesel generator heat exchangers. The air

conditioning unit heat exchanger experienced sufficient forces to stretch the heat

exchanger end bell bolting. These are four recent examples of system damage to one of

the most risk significant systems at Wolf Creek Generating Station. Condition

Report 2008-004983 describes four additional essential service water system water

hammers in 1993, 1995, 1999, and 2004 that resulted in system damage.

Wolf Creek Procedure AI 28A-010, uses a qualitative risk matrix table to determine

whether identified conditions adverse to quality require a root cause analysis. The

matrix describes that risk vulnerability is a product of the probability of an occurrence

and its potential consequence. A qualitative consequence is determined to be marginal

if system damage or a noncritical equipment failure occurs. A qualitative consequence

is determined to be critical if major system damage occurs, or if an event results in a

loss of production or could have resulted in catastrophic consequences under different

circumstances. The widespread corrosion effects on both trains of the essential service

water system and the vulnerability to large leaks after loss of offsite power induced

essential service water water hammer events could be considered critical by these

definitions. These adverse conditions definitely meet the marginal definition. The

matrix describes a qualitative consequence as probable if the condition is likely to occur

several times in the life of an individual system. This frequency was validated by the

multiple examples described above that resulted in through-wall leaks and damage to

the essential service water system supplied heat exchangers. Using the licensee matrix,

the combination of critical and probable results in requirement to conduct a Level 1,

high, root cause analysis. A combination of marginal and probable results in a

requirement to conduct a Level 2, moderately high, root cause analysis. At the time of

inspection, the licensee had initiated two condition reports addressing essential service

water leakage from these adverse conditions. Condition Report 2008-001660 followed

the April 2008 complete loss of offsite power event and water hammer which resulted in

a Level 4, low risk, basic evaluation. The June, July, and August 2009 essential service

water leakage events were rolled together into Condition Report 00018785 that was

screened as a Level 3, moderately low risk, apparent cause evaluation.

The licensee has inspected only a small portion of the essential service water system

piping to identify the magnitude and location of other likely localized corrosion under

deposits. Possible inspection methods include internal inspections and ultrasonic

measurements.

Analysis. The performance deficiency associated with this finding involved the

licensees failure to follow the requirements of Wolf Creek Procedure AI 28A-010.

Specifically, licensee personnel did not effectively screen condition reports for the

adverse conditions of internal corrosion and loss of offsite power induced water

16 Enclosure

hammers to require a root cause analysis. This finding is greater than minor because if

left uncorrected, the failure to fully utilize the corrective action program could become a

more significant safety concern. The inspectors determined that this finding impacted

the Mitigating Systems Cornerstone. Using Manual Chapter 0609.04, Phase 1 - Initial

Screening and Characterization of Findings, the issue screened as having very low

safety significance because it was not a design or qualification deficiency that resulted in

a loss of operability or functionality, did not create a loss of system safety function of a

single train for greater than the technical specification allowed outage times, and did not

affect seismic, flooding, or severe weather initiating events. The cause of this finding is

related to the problem identification and resolution crosscutting component of the

corrective action program because licensee personnel failed to thoroughly evaluate

problems such that the resolutions address causes and extent of conditions P.1(c).

Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities

affecting quality shall be prescribed by documented instructions or drawings of a type

appropriate to the circumstances and shall be accomplished in accordance with these

instructions or drawings. Contrary to the above, prior to September 2009, the licensee

failed to accomplish on activity affecting quality in accordance with documented

instructions. Specifically, as required by Step A.1 of Attachment A to Wolf Creek

Procedure AI 28A-010, Screening Condition Reports, the licensee failed to correctly

determine the appropriate probability associated with occurrences of water hammer

damage and essential service water piping corrosion that resulted in system damage.

Specifically, the licensee did not apply Step A.4.2, Probable, in accordance with the

definition in Step A.4.2, and therefore the licensees application of Step A.6, Qualitative

Risk Matrix, was inappropriate. As a result of the incorrect screening, Condition

Report 00018785 did not require performance of a root cause analysis and did not

evaluate the additive effect of documented loss of offsite power induced water hammers

and internal corrosion. Because of the very low safety significance of this finding and

because the licensee has entered this issue into their corrective action program as Wolf

Creek Condition Report 00022239, this violation is being treated as a noncited violation

in accordance with Section VI.A.1 of the Enforcement Policy:

NCV 05000482/2009007-03, Failure to Correctly Screen Essential Service Water Piping

Leaks for Significance.

1R3 Review of the Licensees Offsite Power System

a. Inspection Scope

The inspectors reviewed the licensees actions for prior instances of loss of the offsite

power lines and whether the licensees actions were commensurate with the number of

previous line failures. Additionally the inspectors assessed the licensees ability to meet

the General Design Criteria requirements for independence of the offsite power lines in

light of conditions surrounding the event.

17 Enclosure

b. Findings

Unresolved Item: 345 kV Offsite Power System Compliance with General Design

Criterion 17

The 345 kV switchyard currently provides both sources of offsite power to the plant. The

original design of the offsite power system included a 345 kV source from the 345 kV

switchyard and a separate 69 kV source from the 69 kV switchyard. In April 1982, the

NRC concluded that the original design was acceptable because the circuits provided

sufficient assurance that redundant and independent sources of offsite power were

provided, as required by General Design Criterion 17. The NRC safety evaluation report

was in two parts. The first described offsite power inside the Standardized Nuclear Unit

Power Plant System design and the second described offsite power to the Wolf Creek

specific Standardized Nuclear Unit Power Plant System (i.e., Wolf Creek). In 1983, Wolf

Creek Generating Station reanalyzed the offsite power system and determined that

changes needed to be made to the Updated Safety Analysis Report. Wolf Creek

Generating Station submitted the revised Updated Safety Analysis Report pages to the

NRC which described the changes to the switchyard and how General Design

Criterion 17 would be met. The significant changes were removing one of the four

proposed 345 kV transmission lines coming into the 345 kV switchyard and adding a

345/69 kV transformer to connect the 345 and 69 kV switchyards. Thus, both offsite

power sources were routed through the common 345 kV switchyard versus from

separate switchyards. In 1985 the NRC concluded that the design changes met the

requirements of General Design Criterion 17 and were acceptable. The removal of this

portion of the USAR was not described in Wolf Creeks submittal and the effective

deletion of the NRCs 1983 safety evaluation report were not described in the NRC

approval. Thus, this Updated Safety Analysis Report change also effectively removed

the second portion of the NRC safety evaluation report from the licensing basis that

described how the plants 345 kV and 69 kV switchyards met the independence

requirements of General Design Criterion 17.

After the NRC approved the offsite power design changes in 1985, Wolf Creek

Generating Station installed an additional 345/13.8 kV transformer. The new

configuration bypassed the 69 kV switchyard and went directly to the onsite XNB01

safety related transformer. In the 10 CFR 50.59 evaluation, Wolf Creek Generating

Station determined that this would be a more reliable source of offsite power than the

previously approved source, which was routed through the 69 kV switchyard. Wolf

Creek Generating Station determined that the new design met General Design

Criterion 17. The inspectors were not able to determine if these design changes were

submitted to the NRC for approval and if the changes, including those in 1983, would

have been accepted as conforming to General Design Criterion 17. Therefore, this issue

is unresolved pending more NRC inspection of the General Design Criterion 17

acceptance criteria applied by Wolf Creek Generating Station and basis and verification

of the removal of the 69 kV system from the offsite power analysis: Unresolved

Item 05000482/2009007-04, 345 kV Offsite Power System Compliance with General

Design Criterion 17.

18 Enclosure

1R4 Review of the Licensees Essential Service Water System

.1 Review of Generic Letter 89-13 and Periodic Verification Program

a. Inspection Scope

The team reviewed the licensees Generic Letter 89-13, Service Water System

Problems Affecting Safety-Related Equipment, program for the essential service water

system including the licensees periodic verification program. As part of their review, the

inspectors examined the licensees response to Generic Letter 96-06, Assurance of

Equipment Operability and Containment Integrity during Design-Basis Accident

Conditions, dated September 30, 1996. Additionally, the inspectors reviewed the

licensees engineering analysis of the system and testing results to ensure the essential

service water system is adequately designed and has the ability to function under

design-basis conditions.

b. Findings and Observations

The team determined that while the licensee had appropriately followed their Generic

Letter 89-13 program for the essential service water system, their implementing

procedures did not result in identifying and correcting pipe wall wastage mechanisms

prior to localized pitting becoming through-wall leaks.

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

Appendix B, Criterion V, Instructions, Procedures, and Drawings, regarding the

licensees failure to provide adequate guidance to identify and address pitting, corrosion,

and surface-breaking flaw indications in the essential service water system. Previous

licensee self-assessment efforts and associated corrective actions recognized the need

for increased monitoring of piping system pitting and wall thinning but had not translated

the need into the implementing procedures such that the service water monitoring

program could address extent of condition.

Description. From 2005 to 2009, at least five examples of through-wall leakage from the

essential service water piping were documented in the Wolf Creek service water

monitoring and corrective action programs. The cause and extent of condition of

essential service water system leaks were not fully addressed by the licensee due to

procedural inadequacies. This was evident because the licensee monitoring efforts

were unable to ensure the continuous system degradation did not reduce essential

service water pipe wall thickness below the minimum allowed ASME code specifications.

The essential service water system is a critical system for the plant because it is tied to

the ultimate heat sink for the facility and because the system is relied upon to provide

appropriate cooling to the heat exchangers and coolers in safety-related systems

needed for accident mitigation or safe-shutdown of the facility. As documented in the

addendum to Wolf Creek Condition Report 00018785, the Wolf Creek essential service

water system has had a history of corrosion and leakage. The licensee only assessed,

and if necessary corrected, degradation in the essential service water system on a case-

by-case basis, and only after determining that the degradation had progressed to an

unacceptable state; that is, only after actual wall thickness for a component was below

the minimum wall thickness requirement or after the component had leaked.

19 Enclosure

NRC Generic Letter 89-13, applies to all holders of operating licenses for nuclear power

generation facilities, and requested that licensees implement augmented activities for

those service water systems that are tied to the ultimate heat sink and that are used to

provide cooling for safety-related systems and components during operational transients

and postulated design basis accidents. These augmented inspection, surveillance, and

maintenance programs were designed to:

• Significantly reduce the incidence of flow blockage problems as a result of

biofouling

• Ensure that corrosion, erosion, protective coating failure, silting, and biofouling

cannot degrade the performance of the safety-related systems supplied by

service water

• Confirm that these type of emergency or essential service water systems will

perform their intended function in accordance with the licensing basis for the

plant

• Confirm that maintenance practices, operating and emergency procedures, and

training that involves these types of service water systems are adequate to

ensure that safety-related equipment cooled by the systems will function as

intended

Wolf Creek implements its Generic Letter 89-13 program in accordance with

administrative Procedures ADM-01-100, Lake Water Systems Inspection, Monitoring

and Maintenance Program, and AP-23L-001 Lake Water Systems Corrosion and

Fouling Program, dated March 21, 2005. These procedures refer to augmented

inspection Procedures QCP-20-518, Visual Examinations of Heat Exchangers and

Piping Components, and WCRE-13, Lake Water Systems Structural Integrity

Program. The purpose of these lake water procedures is to detect degradation in the

essential service water system prior to a leakage event. The inspection procedure for

implementing augmented visual examinations of the essential service water system is

Procedure QCP-20-518.

Procedure WCRE-13 is the augmented volumetric inspection procedure.

Procedure WCRE-13 did not consider essential service water piping with intermediate

flow velocities to be susceptible to wall thinning mechanisms. Intermediate flow velocity

sections of pipe are in WCRE-13, but they were not inspected. It also does not identify

silting deposits (under deposits) as possible sources of microbiologically influenced

corrosion in the essential service water system. This is inconsistent with the definition

for tubercles in visual inspection Procedure QCP-20-518 which does identify that silting

tubercles (under deposits) can be a source of microbiologically influenced corrosion.

The August 19, 2009, leak was through intermediate level velocity piping and was

partially caused by pitting and wall-thinning. The inspection team determined that each

of these procedures have inadequacies that have prevented detection, adequate

expansion of extent of condition testing for microbiologically influenced corrosion, and

thus corrective action for pitting related degradation in the essential service water

system. Thus, significant portions of piping would not have received inspection until

after they suffered through wall leaks.

20 Enclosure

These procedure inadequacies were recognized in 2007 Licensee Self-assessment

Number 76, Lake Water Corrosion, Fouling and Chemistry, which identified:

• A need to establish a pit monitoring program for the essential service water

system

• A need to revise Wolf Creeks volumetric inspection Procedure WCRE-13, to be

consistent with the augmented inspection guidelines in EPRI Service Water

Piping Guideline [EPRI Report TR-1010059]

Corrective action procedures also contributed to the inadequate verification of the

essential service water system material condition. Section 6.1.3 of

Procedure AP 28A-100, Condition Reports, did not identify detection of degradation or

corrosion as an adverse condition for generating condition reports at the facility. As a

result, documentation of corrosion on the inside surfaces of the essential service water

system was not normally translated into appropriate condition reports until either a leak

had occurred or essential service water pipe wall thickness had thinned to below the

minimum ASME Code,Section III, wall thickness requirements. Additionally

documentation of corrosion occurring on the outside surfaces of essential service water

system piping did not occur prior to August 2009.

Analysis. The performance deficiency associated with this finding was a failure to

include appropriate essential service water system quality standards and acceptance

criteria in Procedures QCP-20-518, WCRE-13, and AP 28A-100 to address:

• depth sizing relevant surface-breaking flaw indications and abnormal gross

degradation (such as corrosion, erosion, or wear )

• extent of degradation

• blockage as a result of microbiologically influenced corrosion, macrofouling,

silting or corrosion deposits

As a result of the inadequate procedures, appropriate corrective actions could not occur

when essential service water internal surfaces indicated the presence of corrosion. This

finding is greater than minor because if left uncorrected, the failure to fully utilize the lake

water and corrective action programs could become a more significant safety concern.

The inspectors determined that this finding impacted the Mitigating Systems

Cornerstone. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and

Characterization of Findings, the issue screened as having very low safety significance

because it was not a design or qualification deficiency that resulted in a loss of

operability or functionality, did not create a loss of system safety function of a single train

for greater than the technical specification allowed outage times, and did not affect

seismic, flooding, or severe weather initiating events. This finding has a crosscutting

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

action program because licensee personnel failed to take appropriate corrective actions

to address safety issues and adverse trends in a timely manner P.1(d).

Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities

affecting quality shall be prescribed by documented instructions or drawings of a type

21 Enclosure

appropriate to the circumstances and shall be accomplished in accordance with these

instructions or drawings. Contrary to the above, prior to September 2009,

Procedures QCP-20-518, Visual Examinations of Heat Exchangers and Piping

Components, and AP 28A-100, Condition Reports, were not appropriate to the

circumstances because the licensee failed to include appropriate quality standards and

acceptance criteria for corrosion in the essential service water system. As a result of

these procedural deficiencies, the licensee did not evaluate the affect of documented

internal corrosion. Because of the very low safety significance of this finding and

because the licensee has entered this issue into their corrective action program as

Condition Report 00022243 this violation is being treated as a noncited violation in

accordance with Section VI.A.1 of the Enforcement Policy: NCV 05000482/2009007-05,

Failure to Ensure Adequate Acceptance Criteria and Extent of Condition Guidance in

Lake Water and Corrective Action Program Procedures.

.2 Review of the Bases for Insulating Essential Service Water Piping

a. Inspection Scope

The team evaluated the licensees bases for insulating the essential service water

system piping in the auxiliary building. The licensees design drawings and design basis

documentation were reviewed. Also, key personnel from design and system engineering

were interviewed.

b. Findings

No findings of significance were identified.

.3 Review of the Evaluation for Piping Structural Integrity

a. Inspection Scope

The team evaluated the licensees evaluation of the structural integrity of the essential

service water system piping with the 3/8-inch hole which had developed during the

event. In their evaluation, the licensee applied Code Case N-513-2 to the ASME Piping

Code. This code case required the licensee to perform additional monitoring of the

essential service water system piping. The team reviewed acceptability of the chosen

monitoring the licensee adopted. Key personnel from operations, design and system

engineering, maintenance, and the corrective action program were interviewed. The

NRC Office of Nuclear Reactor Regulation also provided technical assistance to the

inspection team during the review of this area (Attachment 3).

b. Findings

No findings of significance were identified.

.4 Review of Essential Service Water System Piping Repairs

a. Inspection Scope

The team evaluated the licensees repairs to the 3/8-inch hole in the essential service

water system piping that occurred during the event. The licensee also discovered

22 Enclosure

another area that was below the minimum wall thickness prescribed by the American

Society of Mechanical Engineering Code after the event. This condition and its repair

was also reviewed by the team. Key personnel from operations, design and system

engineering, maintenance, and the corrective action program were interviewed.

b. Findings

No findings of significance were identified.

1R5 Review of Plant Systems during the Event

.1 Observed Pressure Oscillations in the Auxiliary Feedwater System

a. Inspection Scope

During the event, the senior resident inspector noted there was indication that the

pressure in the auxiliary feedwater system at the suction of the pumps was oscillating.

The team reviewed the acceptability of the observed pressure oscillations observed on

the suction of the auxiliary feedwater pumps and their impact on system operability and

technical specifications. Applicable system piping and instrumentation diagrams along

with system isometrics drawings were reviewed. Also, the team walked down the

auxiliary feedwater system suction piping to verify the drawings and assumptions the

licensee made relative to the indications and their impact on the system. Finally, key

personnel from operations, design and system engineering, maintenance, and the

corrective action program were interviewed.

b. Findings

No findings of significance were identified.

.2 Water Hammer on the Essential Service Water System

a. Inspection Scope

The team verified that a water hammer occurred on the essential service water system

on August 19, 2009. The team noted multiple previous examples of water hammer

occurrences were documented in the licensees corrective action system as mentioned

and detailed in Condition Report 2008-004983.

The team evaluated the licensees procedures for water hammer response and

corrective actions to previous water hammer events. The licensees response to

Generic Letter 96-06, Assurance of Equipment Operability and Containment Integrity

During Design-basis Accident Conditions, was reviewed. Key personnel from

operations, design and system engineering, maintenance, and the corrective action

program were interviewed.

b. Findings

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

Appendix B, Criterion V, Instructions, Procedures, and Drawings, regarding the

licensees failure to provide adequate guidance to address the impact of a loss of offsite

power event on the essential service water system.

23 Enclosure

Description. On August 19, 2009, a leak of approximately 20 gpm from the essential

service water system piping occurred on the 1988 elevation level of the auxiliary

building concurrent with a loss of offsite power event. This plant area was not frequently

entered by plant personnel. The plants emergency diesel generators started per design

and sequenced on safety loads including two trains of essential service water pumps.

The design of the load sequencing subjects the plant essential service water piping to a

water column separation from the piping high point. Wolf Creek

Procedure STN PE-040G, Transient Event Walkdown, required that several plant

systems subject to expected transient dynamic forces following a reactor trip to have a

post-trip walkdown to identify any structural damage from the off-normal forces. The

walkdown procedure did not identify the essential service water system as vulnerable to

such dynamic forces. However, the procedures Appendix H did allow for operations

shift management to designate additional systems to walk down following reactor trip

events. This procedure was used in a very similar loss of offsite power induced water

hammer on April 7, 2008. That event recognized an essential service water piping

walkdown was needed after leakage from several locations had been identified.

With the current essential service water system design, every loss of offsite power event

at Wolf Creek will result in a water column separation and subsequent re-pressurization

by the loss of normal service water pumps and the sequencing on of the essential

service water pumps. This phenomenon was not specifically described in the licensees

Updated Safety Analysis Report; however, it had been clearly identified in previous Wolf

Creek condition reports (00012990, 00009688, 2008-005075, 2008-004983, and 2008-

001660). This was also evident by Wolf Creeks response to NRC Generic Letter 96-06,

Assurance of Equipment Operability and Containment Integrity During Design-Basis

Accident Conditions, September 30, 1996. Despite the abundant internal operating

experience, Procedure STN PE-040G did not identify essential service water as a

required walkdown system. The post-trip walkdown procedure only required walkdowns

inside the containment building unless specified by operating department shift

supervisors. From the recent implementation of the procedure, outside containment

piping system damage must be self-evident to result in usage of STN PE-040G,

Appendix H. The August 19, 2009, leak was discovered approximately seven hours

after the reactor trip by the NRC resident inspectors and not by the licensee. The

resident inspectors had noted one to three inches of water buildup on the floor one level

below the elevation where the leak had occurred seven hours earlier.

Analysis. The performance deficiencies of this finding are the inadequate walkdown

procedure for post loss of offsite power reactor trips and the failure of the operations

crew to recognize the need to require a walkdown of the essential service water system

in its entirety following the loss of offsite power and reactor trip. This finding is more

than minor because it is associated with the Mitigating Systems Cornerstone attribute of

procedure quality and adversely affects the objective to ensure equipment availability

and reliability. This finding is of very low safety significance because it was not a design

deficiency or qualification deficiency, did not represent a loss of system safety function,

did not represent an actual loss of safety function of one or more non-technical

specification trains of equipment designated as risk-significant, and was not potentially

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

finding is related to the area of problem identification and resolution and is associated

with the operating experience crosscutting component because the licensee failed to use

information, including vendor recommendations, and internally generated lessons

24 Enclosure

learned, to support plant safety. Specifically, the licensee failed to implement and

institutionalize operating experience through changes to station walkdown procedures

P.2(b).

Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities

affecting quality shall be prescribed by documented instructions or drawings, of a type

appropriate to the circumstances and shall be accomplished in accordance with these

instructions or drawings. Contrary to the above, Procedure STN PE-040G, Transient

Event Walkdown, was not appropriate to the circumstances in that it was not adequate

to detect essential service water system damage on August 21, 2009. Because of the

very low safety significance and Wolf Creeks action to place this issue in their corrective

action program as Condition Report 00022265, this violation is being treated as a

noncited violation in accordance with Section VI.A.1 of the Enforcement Policy:

NCV 05000482/2009007-06, Inadequate Procedure Resulted in Failure to Discover

Essential Service Water System Leakage Following a Water Hammer Event.

.3 Impact on Internal Flood Control Mitigation Capability

a. Inspection Scope

The team noted that water from the essential service water system was entering the

auxiliary building and that the plants room drain pump were powered from non-

emergency sources. In light of this, the team reviewed the design and operation of the

internal flood control features in the plant and their ability to mitigate a leak during a

sustained loss of offsite power event. Pertinent plant drawings were reviewed. Also,

key personnel from operations and engineering were interviewed.

b. Findings

No findings of significance were identified.

.4 Effects of Loss of Power to Plant Radiation Monitors

a. Inspection Scope

During the event, numerous radiation monitors lost power. Due to their design, some

required resetting and other actions to place them back in to operation. The team

reviewed monitors that were unavailable at any time during or after the event and

determine if any of the radiation monitor failures experienced in the event would have

hampered further actions (e.g., implementing the emergency plan). The team reviewed

plant logs, plant computer system data, and the licensees emergency action level

procedures to evaluate the effects. Also, key personnel from radiation protection,

emergency planning, and maintenance were interviewed.

b. Findings

No findings of significance were identified.

25 Enclosure

.5 Partial Loss of Fire Detection System Capability

a. Inspection Scope

The team reviewed the actions taken for the loss of fire detection capability in the

auxiliary building during the event. In their review, the team sought to establish if this

loss of detection capability was anticipated in plant design.

b. Findings

1. Operations Department Actions to Compensate for the Loss of Detection

Introduction. The team identified a Green noncited violation of License

Condition 2.C.(5), Fire Protection, for the failure to establish a compensatory fire watch

in a timely manner per the station fire protection program.

Description. On August 19, 2009, a complete loss of offsite power resulted in a reactor

trip. Immediately after the trip, fire protection trouble alarms came in on fire protection

panel KC-008. The control room supervisor acknowledged the alarms and verified that

every smoke detector in window 109 of the panel was in a trouble alarm state. The

control room supervisor dispatched personnel to verify a fire existed in accordance with

Procedure OFN KC-016, Fire Response. Licensee personnel reported that a fire did

not exist in the location of the alarming smoke detectors. Since there was not an actual

fire, the procedure directed the control room supervisor to exit Procedure OFN KC-016

and enter alarm Procedure ALR KC-888, Fire Protection Panel KC-008 Alarm

Response. Step 4.3.1 required, in part, the operator to take appropriate compensatory

measures per administrative Procedure AP 10-103, Fire Protection Impairment Control,

for the smoke detectors that were in a trouble alarm state.

The control room supervisor was preoccupied with actions related to the reactor trip and

did not perform the required action to initiate a fire protection impairment. The control

room supervisor assigned the action to the nightshift control room supervisor during the

shift turnover. The nightshift control room supervisor subsequently assigned the action

to the nightshift shift engineer. The nightshift shift engineer failed to initiate the

appropriate compensatory measures for the alarming smoke detectors. The next

morning, the NRC senior resident inspector questioned why no impairment had been

established for the alarms on KC-008. The dayshift shift engineer subsequently

discovered the detectors were inoperable and issued the impairment for the 13 affected

fire zones.

The team determined that a significant contributor to the finding was that the licensee did

not follow their procedures as required. Both the dayshift and nightshift control room

supervisors delegated the responsibility of initiating the impairment and failed to verify

that the task was completed. Not having proper compensatory measures in place added

unnecessary risk to the plant.

Analysis. The licensees failure to initiate fire protection impairment and establish an

hourly fire watch for the areas impacted by the inoperable fire detectors was a

performance deficiency. The finding was more than minor since it was associated with

the protection against the external factors attribute of the Mitigating Systems

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

26 Enclosure

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

undesirable consequences. Using Manual Chapter 0609, Appendix F, Fire Protection

Significance Determination Process, the inspectors determined that this finding had an

adverse affect on the fixed fire protection systems element of fixed fire detection

systems. The inspectors assigned a high degradation rating due to the fact that all the

smoke detectors in the fire zones were inoperable. Because the system was degraded

without compensatory actions for approximately 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> and licensee personnel were

walking through the auxiliary building performing post-trip actions, senior reactor

analysts determined this finding to be of very low safety significance. This finding had a

crosscutting aspect in the area of human performance associated with the work

practices component because the licensee failed to ensure supervisory oversight of work

activities such that nuclear safety is supported H.4(c).

Enforcement. License Condition 2.C.(5) states, in part, that the licensee shall maintain

in effect all provisions of the approved fire protection program as described in the

Standardized Nuclear Unit Power Plant System (SNUPPS) Final Safety Analysis Report

for the facility through Revision 17, the Wolf Creek Site Addendum through Revision 15,

and as approved in the Safety Evaluation Report through Supplement 5. The Wolf

Creek Updated Safety Analysis Report combined the SNUPPS Final Safety Analysis

Report, Revision 17, and the Wolf Creek Site Addendum, Revision 15, into one

document. Updated Safety Analysis Report, Appendix 9.5A, Section B, Administrative

Procedures, Controls and Fire Brigade, states that work control procedures, which

include identification of the need for special action such as a fire watch, are utilized.

Contrary to the above, the licensee failed to utilize work control procedures to identify

the need for a special action (fire watch). Specifically, the licensee did not issue a fire

protection impairment and implement an hourly fire watch within one hour as required by

administrative Procedure AP 10-103, Fire Protection Impairment Control. This issue

and the corrective actions are being tracked by the licensee in Condition

Report 00019320. Because the finding is of very low safety significance and has been

entered into the corrective action program, this violation is being treated as a noncited

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

NCV 05000482/2009007-07, Failure to Initiate Timely Fire Protection Impairment

Control Permit and Implement Compensatory Measures.

2. Uncontrolled and Unanalyzed Room Environment Following a Loss of Offsite Power

The Wolf Creek Station Blackout Coping Assessment, Section 4.5, evaluated the Effects

of Loss of Ventilation, associated with the loss of offsite power. Specifically, the

assessment evaluated the loss of auxiliary building ventilation effects on the environment

surrounding the turbine-driven auxiliary feedwater pump room. The evaluation states:

It is shown that the turbine-driven auxiliary feedwater pump room air temperature will

stay below 150 degrees Fahrenheit turbine-pump design specifications provided actions

are taken to open doorways to enhance air circulation. The final steady state

temperature of the room is determined by a NUMARC methodology. This methodology

assumed an open door formula; that is, a need to open the four other doors adjacent to

the corridor outside the turbine-driven auxiliary feedwater pump room. This action was

not performed during the August 19, 2009, loss of offsite power/loss of auxiliary building

ventilation event. Due to this, temperatures in the corridor were recorded above the

assumed maximum of 113 degrees Fahrenheit using the open door formula. With the

doors remaining closed, the calculation determined that the turbine-driven auxiliary

27 Enclosure

feedwater pump room temperatures would rise to 170 degrees Fahrenheit, which is

above that allowable to maintain the rooms equipment operable.

The turbine-driven auxiliary feedwater pump steam drain traps in room 1206/1207 below

the corridor exhausted to the floor drains. During steady-state conditions, the ventilation

system keeps the steam from accumulating in the room. However, during a loss of

offsite power event, the ventilation system no longer functions and the steam heats up

the room. This additional heat source to the corridor was not accounted for in the station

blackout analysis and created conditions not previously analyzed associated with

room 1206/1207. The licensee did not provide an adequate evaluation or adequate

procedural guidance to address the impact of a loss of offsite power on the auxiliary

feedwater system.

The concerns associated with the steam environment in room 1206/1207 below the

auxiliary feedwater pump rooms were:

• The safety related transmitters for condensate storage tank swap-over could be

challenged

• The seismic supports for essential service water piping in the room could be

affected by the increased local temperature

• Manual operator actions to manipulate an essential service water motor operated

valve could be challenged due to visibility and local temperatures

This issue is unresolved pending further NRC inspection of the evaluation by Wolf Creek

Generating Station associated with steam exhausting into rooms 1206/1207 and the

corridor outside the auxiliary feedwater pump rooms following a loss of offsite power:

Unresolved Item 05000482/2009007-08, Uncontrolled and Unanalyzed Room

Environment Following a Complete Loss of Offsite Power.

1R6 Review of the Post-Trip Report

a. Inspection Scope

The team reviewed the licensees post-trip report prepared for analyzing the event. The

report was initially reviewed prior to plant restart and again during the onsite portion of

the special inspection. The team interviewed key personnel from operations and

engineering to discuss the findings of the report.

b. Findings

No findings of significance were identified.

1R7 Review of High Level in Steam Generator Following the Event

a. Inspection Scope

On August 21, 2009, the licensee reported to the NRC a condition in which the level in

Steam Generator A exceeded the 78 percent level. The team reviewed the licensees

report, control room logs, plant computer data, and pertinent plant operating procedures.

Also, key personnel from the operations department were interviewed.

28 Enclosure

b. Findings

Introduction. A self-revealing Green noncited violation of Technical Specification 5.4.1.a,

Procedures, was reviewed involving a failure to monitor and maintain steam generator

water levels resulted in an unanticipated turbine trip signal and feedwater isolation.

Description. On August 21, 2009, while in Mode 3, Wolf Creek control room received

annunciator 112A, S/G LEVEL HIGH TURB TRIP. This was caused by operator

inattention during shift turnover. Steam generator A level had increased to the

78 percent, P-14 feedwater isolation actuation setpoint. This was above the 40 percent

to 60 percent operating band designated in Procedure GEN-OO-005, Minimum Load to

Hot Standby, and created the P-14 feedwater isolation, an engineered safeguards

actuation signal. Control room operators responded to the feedwater isolation by

restoring steam generator water levels to the program band.

The licensee had been having difficulties maintaining steam generator water levels since

the reactor trip from full power on August 19, 2009. These difficulties were due to

staying in Mode 3, steaming the steam generators with no automatic feedwater control,

and atmospheric relief valves periodically releasing steam. The practice established had

been to secure auxiliary feedwater flow as soon as an established operator selectable

alarm indicated that Steam generator A was at 65 percent. This allowed for an

anticipated additional 5 percent level increase due to swell of the introduced colder

auxiliary feedwater and another 5 percent level increase caused by opening of the

atmospheric relief valve.

The licensee determined that the oncoming shift operators had disabled an operator

selectable alarm due to the constant alarms being a distraction. The trip signal and

actuation occurred while the operators were walking down the control boards for shift

turnover. Thus there were no additional operators monitoring the steam generator A

level. Disabling the operator selectable alarm, not having a dedicated operator

monitoring steam generator water levels when in manual control, and intentionally

allowing levels to go above the control band were all contrary to licensee

Procedure AI 21-100, Operations Guidance and Expectations.

Analysis. The performance deficiency associated with this finding involved the failure to

control and maintain steam generator water levels as required in

Procedure GEN-OO-005. This finding was determined to be greater than minor because

it impacted the Initiating Events Cornerstone attribute of human performance and

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

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

operations. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and

Characterization of Findings, this finding was determined to be of very low safety

significance since it did not affect the technical specification limit for reactor coolant

system leakage or mitigation systems safety function, did not contribute to both the

likelihood of a reactor trip and mitigation equipment or functions not being available, and

did not increase the likelihood of a fire or internal/external flooding. The finding has a

crosscutting aspect in the area of human performance associated with the decision

making component because the licensee failed to make safety-significant or risk-

significant decisions using a systematic process, especially when faced with uncertain or

unexpected plant conditions [H.1 (a)].

29 Enclosure

Enforcement. Technical Specification 5.4.1.a, Procedures, required that written

procedures be established and implemented covering activities specified in Appendix A,

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

Assurance Program Requirements (Operation), February 1978. Regulatory Guide 1.33,

Appendix A, Section 2.i, requires procedures for plant shutdown to hot standby.

Contrary to the above, on August 21, 2009, operators failed to implement

Procedure GEN-OO-005, Minimum Load to Hot Standby. Specifically the operators

failed to control and maintain steam generator water levels between 40-60 percent as

required in Step 7.4 of Section 7.0, Final Conditions. Because of the very low safety

significance and Wolf Creeks action to place this issue in their corrective action program

as Condition Report 00019295, this violation is being treated as a noncited violation in

accordance with Section VI.A.1 of the Enforcement Policy: NCV 05000482/2009007-09,

Failure to Adequately Control Steam Generator Water Levels.

1R8 Verification of Meeting Reporting Requirements

a. Inspection Scope

The team reviewed the conditions which occurred due to the event and the reports the

licensee made to the NRC per 10 CFR Part 50.72, Immediate Notification

Requirements for Operating Nuclear Power Plants, and 10 CFR Part 50.73, Licensee

Event Report System. The team also interviewed key personnel from the operations,

licensing, and emergency planning departments to discuss the content of and bases for

their reports.

b. Findings and Observations

No findings of significance were identified. The review of Licensee Event

Report 05000482/2009-002-00 issued for the event are discussed in Section 4OA3 of

this report.

1R9 Review of Compliance with Technical Specifications

a. Inspection Scope

The team reviewed the conditions which occurred during and after the event relative to

the actions taken by the licensee to review the licensees compliance to their technical

specifications. The team also interviewed key personnel from the operations and

licensing departments.

b. Findings and Observations

One finding of significance is documented in Section 4OA7 of this report.

1R10 Review of Licensees Decision to Maintain the Plant in Mode 3 After the Event

a. Inspection Scope

The team reviewed the conditions which occurred after the event, specifically relative to

the licensees decision to keep the plant in a hot standby condition rather than opting to

30 Enclosure

shut down and cool down the plant. The team reviewed plant procedures and

interviewed key personnel from the operations and licensing departments in this effort.

b. Findings and Observations

No findings of significance were identified.

1R11 Review of Application of Emergency Action Level Scheme

a. Inspection Scope

The team reviewed the plant conditions which occurred after the event, specifically

relative to whether the conditions met any entry conditions which would have required

the licensee to declare a Notice of Unusual Event. The team reviewed plant procedures

and interviewed key personnel from the emergency planning, operations, and licensing

departments in this effort.

b. Findings and Observations

NRC inspectors reviewed licensee Procedure APF 06-002-01, Emergency Action

Levels (EAL). The inspectors noted that the offsite power feeds to the 4 kV essential

NB system busses were not restored until 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 50 minutes following the event,

and the licensee did not report a Notice of Unusual Event. The team concluded this was

in accordance with the licensees EAL procedures because those procedures described

that power interruptions to the NB transformers for less than 15 minutes would be

considered momentary power losses and would not be required to be declared as a

Notice of Unusual Event.

The team observed that any interruption of power to the 4 kV essential busses (as

described in their EAL basis document) would have been difficult to recover from in less

than 15 minutes. Because Wolf Creek training documents and the implementing

emergency action level procedure specified restoring power to the NB transformers (and

not the 4 kV busses) and did not emphasize when the 15 minutes to restore power to the

4 kV NB essential bus should start, the inspectors determined that no findings of

significance had occurred.

Because they observed a disparity between the licensees EAL procedure and bases,

the team reviewed the potential scenario of having 15 minutes to restore power to the 4

kV busses alluded to in the EAL bases. The team reasoned that much of the 15 minutes

could be used by the shift manager/emergency coordinator to verify that the crew is

correctly performing its emergency response immediate actions, obtaining emergency

action level procedural guidance, assessing the plant to determine which emergency

action levels may be applicable, diagnosing the plant event effect on the switchyard and

the 4 kV NB essential bus support components and determining what available

personnel can be diverted from the emergency procedures and fire brigade response

duties. The shift manager may also be involved in communications with the

transmission grid operator to understand the grid status during this time. The team

concluded that the time needed to perform these actions coupled with the time to

perform bus power restoration Procedure OFN-NB-030, Loss of AC Bus NB01 (NB02),

could consume much, if not all, of the prescribed 15 minutes to restore power to the

NB busses had the procedure specified that the 15 minutes would start at the initiation of

31 Enclosure

the loss of all offsite power. From this, the inspectors determined that performing the

associated emergency procedures would severely challenge a crews resources making

it questionable whether the crews actual event response would ever be to able restore

offsite power to the 4 kV NB essential busses within 15 minutes, requiring the licensee

would have had to declare a Notice of Unusual Event.

The team also noted other factors specific to the August 19, 2009, loss of offsite power

event which would prolong the time to restore power. During this event, operators took

27 minutes to complete the procedural steps which directed them to transition to bus

restoration Procedure OFN-NB-030. Also, reports from licensee personnel of smoke

near the NB system transformers during the event that day, the presence of actuated fire

alarms in the nearby turbine building and auxiliary building during the event that day, and

the presence of a trouble alarm for each of the NB system transformers were factors

which could have influenced the emergency coordinators decision that power could be

restored to the 4 kV NB essential busses within 15 minutes.

The team shared their observations with the licensee. The licensee entered this

apparent procedural disparity condition into their corrective action program. .

4. OTHER ACTIVITIES

4OA3 Event Follow-up (71153)

(Closed) Licensee Event Report 05000482/2009-002-00: Loss of Offsite Power due to

Lightning

Licensee Event Report 05000482/2009-002-00 was issued on October 17, 2009, after

the onsite portion of the inspection. The events and facts detailed in this Licensee Event

Report were covered and reviewed as part of this special inspection. The licensee has

initiated appropriate corrective actions. No findings of significance were noted. This

Licensee Event Report is closed.

(Closed) Licensee Event Report 05000482/2009-004-00: Feedwater Isolation on High

Water Level in A Steam Generator

Licensee Event Report 05000482/2009-004-00 was issued on October 18, 2009, after

the onsite portion of the inspection. The events and facts detailed in this Licensee Event

Report were covered and reviewed as part of this special inspection. The licensee has

initiated appropriate corrective actions. One finding of significance was noted and is

contained in Section 1R7 of this report. This licensee event report is closed.

4OA6 Meetings, Including Exit

On September 25, 2009, the team presented the preliminary results of this inspection at

the end of the onsite week to Mr. Rick A. Muench, President and Chief Executive Officer,

and other members of his staff who acknowledged the findings. The team verified that

no proprietary information was retained.

On December 22, 2009, the team leader presented the final results of the inspection to

Mr. Matt Sunseri, Vice President Operations and Plant Manager, and other members of

the licensee staff who acknowledged the findings. The team verified that no proprietary

information was retained.

32 Enclosure

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the

licensee and is a violation of NRC requirements which meets the criteria of Section VI of

the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a noncited

violation.

Technical Specification 5.4.1, Procedures, required that written procedures be

established and implemented covering activities specified in Appendix A, Typical

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

Assurance Program Requirements (Operation), February 1978. Regulatory Guide 1.33,

Appendix A, Section 6.c, required procedures for combating emergencies and other

significant events. Contrary to the above, from November 2, 2007, to August 19, 2009,

Procedure EMG ES-02, Reactor Trip Response, was inadequate for restoration of

essential service water cooling to instrument air compressors. Specifically, Step 5a,

response not obtained, incorrectly directed operators to locally open valves EFHV0043

and EFHV0044. This action takes the valves out of their normal position and prevents

their automatic isolation on a high flow condition. The unavailability of this automatic

feature makes each train of essential service water inoperable. This finding is greater

than minor because it was associated with the Mitigating Systems Cornerstone attribute

of procedural quality and it affected the cornerstone objective to ensure the availability,

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

undesirable consequences. Using Manual Chapter 0609.04, Phase 1 - Initial

Screening and Characterization of Findings, the issue screened as very low safety

significance because it was not a design or qualification deficiency that resulted in a loss

of operability or functionality, did not create a loss of system safety function of a single

train for greater than the technical specification allowed outage time and did not affect

seismic, flooding, or severe weather initiating events. This finding was entered in the

licensees corrective action program as Condition Report 00019660

33 Enclosure

ATTACHMENT 1

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Birzer, Lake Water Engineering

B. Blecha, Supervisor, Maintenance

W. Camp, Control Room Supervisor

A. Critchly, Corrective Action Technical Specifications

T. Damashek, Superintendent, Operations Support

D. Dees, Superintendent, Operations

B. Dorathy, Supervisor, Systems Engineering

T. Dougan, Quality

D. Erbe, Manager, Security

R. Flannigan, Manager, Regulatory Affairs

M. Free, Senior Nuclear Safety Officer

C. Garcia, Supervisor, Systems Engineering

R. Gardner, Manager Quality, Performance Improvement and Assessment

T. Garrett, Vice President, Engineering

D. Gholson, Reactor Operator

S. Good, Security

S. Hedges, Vice President, Oversight

D. Helm, Supervisor, Supervisor, Systems Engineering

S. Henry, Manager, Operations

R. Hubbard, Shift Manager, Operations

W. Kennamore, Manager Nuclear Engineering

B. Ketchum, Probabilistic Safety Analysis, Nuclear Engineer

M. Kewley, Senior Nuclear Safety Officer

G. Kinn, Supervisor, Nuclear Engineering

S. Koenig, Manager, Corrective Action

B. Masters, Supervisor, Design Engineering

D. McClure, Senior Reactor Operator

R. Muench, President and Chief Executive Officer

B. Muilenburg, Licensing

J. Myers, Reactor Operator

G. Neisis, Manager Design

W. Norton, Manager IPS/Scheduling

G. Pendergrass, Manager Systems Engineering

C. Peterson, Senior Nuclear Safety Officer

D. Phelps, Owners Representative

L. Ratzlaff, Manager Support Engineering

E. Ray, Manager, Chemistry/Health Physics

L. Rockers, Licensing

L. Solorio, Design Engineer

M. Sunseri, Vice President Operations and Plant Manager

B. Vickery, Supply Chain Manager

M. Westman, Manager, Training

S. Yunk, Senior Reactor Operator/Shift Technical Advisor

A1-1 Attachment 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000482/2009007-01 FIN Failure to Enter Adverse Conditions into the Corrective

Action Program (Section 1R2)05000482/2009007-02 NCV Failure to Perform an Operability Evaluation (Section 1R2)05000482/2009007-03 NCV Failure to Correctly Screen Essential Service Water Piping

Leaks for Significance (Section 1R2)05000482/2009007-05 NCV Failure to Ensure Adequate Acceptance Criteria and Extent

of Condition Guidance in Lake Water and Corrective Action

Program Procedures (Section 1R4)05000482/2009007-06 NCV Inadequate Procedure Resulted in Failure to Discover

Essential Service Water System Leakage Following a Water

Hammer Event (Section 1R5)05000482/2009007-07 NCV Failure to Initiate Timely Fire Protection Impairment Control

Permit and Implement Compensatory Measures

(Section 1R5)05000482/2009007-09 NCV Failure to Adequately Control Steam Generator Water Levels

(Section 1R7)

Opened

05000482/2009007-04 URI 345 kV Offsite Power System Compliance with General

Design Criterion 17 (Section 1R3)05000482/2009007-08 URI Uncontrolled and Unanalyzed Room Environment Following

a Complete Loss of Offsite Power (Section 1R5)

Closed

05000482/2009-002-00 LER Loss of Offsite Power due to Lightning (Section 4OA3)

05000482/2009-004-00 LER Feedwater Isolation on High Water Lever in A Steam

Generator (Section 4OA3)

DOCUMENTS REVIEWED

PROCEDURES

NUMBER TITLE REVISION / DATE

0400 Westar Energy, Inc. Transmission Operations Procedure July 28, 2008

0414 Westar Energy, Inc. Transmission Operations Procedure May 1, 2009

A1-2 Attachment 1

PROCEDURES

NUMBER TITLE REVISION / DATE

ADM 01-100 Lake Water Systems Inspection, Monitoring and March 21, 2005

Maintenance

AFP 06-002-01 Emergency Action Levels 12

AI 21-100 Operations Guidance and Expectations 15

AI 26A-003 Regulatory Evaluations (Other Than 10 CFR 50.59) 10

AI 28A-001 Level 1 CR Evaluation (IIT) 10

AI 28A-006 Level 3 Condition Report Evaluation 7

AI 28A-007 Level 2 CR Evaluation 2

AI 28A-008 Level 4 CR Evaluation 2

AI 28A-010 Screening Condition Reports 3A

ALR KC-888 Fire Protection Panel KC-008 Alarm Response 16

ALR 831 ESF Transformer XNB01 3

ALR832 EXF Transformer XNB02 3

ALR 00-019D XNB01 Transformer Trouble 9

ALR 00-022D XNB02 Transformer Trouble 9

ALR 00-127D Condensate Storage Tank Level LoLo 2 7

ALR 00-127E Condensate Storage Tank Level LoLo 1 10A

AP 10-10 Fire Protection Impairment Control. 23

AP 10-100 Fire Protection Program 14

AP 10-103 Fire Protection Impairment Control 11 and 21

AP 10-104 Breach Authorization 22

AP 10-106 Fire Preplans 8

AP 21-001 Conduct of Operations 43

AP 23I-001 Fatigue Management 1

AP 23L-001 Lake Water Supply Corrosion and Fouling Programs March 21, 2005

A1-3 Attachment 1

PROCEDURES

NUMBER TITLE REVISION / DATE

AP 26C-004 Technical Specification Operability 20

AP 28-001 Operability Evaluations 17

AP 28A-100 Condition Reports 10

AP-21C-001 WCGS/Westar Substation 9

APF 06-002-01 Emergency Action Levels 12

BD-EMG C-0 Loss of All AC Power 11

EMG-E-0 Reactor Trip or Safety Injection 24

EMG ES-02 Reactor Trip Response 18

EPP 06-001 Control Room Operations 13

GEN-OO-005 Minimum Load to Hot Standby 62

OFN AF-025 Unit Limitations 27

OFN KC-016 Fire Response 22

OFN-NB-030 Loss of AC Emergency Bus NB01(NB02) 22

STN PE-040G Transient Event Walkdown 1

STS NB-005 Breaker Alignment 4A

STS RE-004 Shutdown Margin Determination 25

SYS NB-201 Transferring NB01 Power Sources 42

SYS NB-202 Transferring NB02 Power Sources 37

QCP 20-518 Visual Examinations of Heat Exchangers and Piping 5A

Components

WCRE-13 Lake Water Systems Structural Integrity Program 5A

DRAWINGS

NUMBER TITLE REVISION

M-12 AL01 Auxiliary Feedwater System Drawing

M-12 AN01 Piping and Instrumentation Diagram Demineralized Water 8

A1-4 Attachment 1

DRAWINGS

NUMBER TITLE REVISION

Storage and Transfer System

M-12 AP01 Condensate Storage and Transfer System 8

M-12 FC02 Auxiliary Turbines System Drawing

M-13 AL01 Piping Isometric Auxiliary Feedwater Pumps Suction Piping 10

10466-J-110- Instrument Loop Diagram for Auxiliary Feedwater Supply 0

0357-W06 Pressure from Condensate Storage Tank

TI 2AC-175 Foxboro Spec 200 Dynamic Compensator 0

Gould Pumps Inc. Floor Drain Tank Pumps 3

765502

CONDITION REPORTS

00003599 00006780 00007499 00007502 00007508

00007509 00007510 00007511 00009519 00009688

00011704 00012990 00013805 00014261 00014930

00015520 00015521 00015574 00015634 00016358

00016901 00016905 00017900 00018217 00018646

00018785 00018817 00019079 00019219 00019248

00019284 00019295 00019308 00019320 00019660

00019716 00019724 00019806 00019918 00019951

00019955 00019960 00020022 00020050 00020068

00020097 00020099 00022247 2007-001531 2007-001780

2007-001993 2007-002009 2007-002162 2007-002656 2007-003350

2007-003378 2007-004125 2007-004126 2007-004127 2007-004128

2007-004129 2007-004130 2007-004131 2007-004132 2008-000116

2008-001448 2008-001450 2008-001456 2008-001457 2008-001458

2008-001459 2008-001479 2008-001481 2008-001485 2008-001494

2008-001511 2008-001642 2008-001660 2008-001797 2008-001819

2008-001932 2008-002280 2008-002785 2008-003745 2008-004536

2008-004592 2008-004983 2008-005075 2009-000250

PERFORMANCE IMPROVEMENT REQUESTS

1994-08237 1995-0558 1997-03965 2002-083 2000-2122

2003-2178 2004-2435 2004-2441 2004-2683 2005-2167

2005-2619 2007-003378 2008-005913

A1-5 Attachment 1

CALCULATIONS

NUMBER TITLE REVISION /

DATE

01030-C-001 Reanalysis of Pipe Stress Calculation P-093A for Containment

Cooler Return Line

01030-C-002 Incorporate Dynamic Loads due to Water Hammer on May 17, 2001

Containment Coolers

FL-01 Flooding of the Auxiliary Building 1

FL-03 Flooding of Individual Aux Bldg Rooms 0

M-FL-04 Summary of Flood Levels in all Auxiliary Building Rooms due 1

to Pipe Break or Crack

XX-E-013 Post Fire Safe Shutdown (PFSSD) Analysis including change 1

notices

XX-E-009 System NB,NG,PG Undervoltage/Degraded Voltage Relay 1

Setpoints, including attachments

XX-E-006 AC System Analysis including attachments and change 5

notices

Engineering Change Package 05818 for Containment Cooler

Support Installations

CORRESPONDENCE

NRC Generic Letter 96-06, Assurance of Equipment Operability and Containment Integrity during

Design-Basis Accident Conditions, September 30, 1996

NRC Generic Letter 2006-02, Grid Reliability and the Impact on Plant Risk and the Operability of

Offsite Power, February 1, 2006

ET 07-0003, Wolf Creek Nuclear Operating Corporation Response to NRC Additional Request for

Additional Information RE: NRC Generic Letter 2006-02, Grid Reliability and the Impact on Plant

Risk and the Operability of Offsite Power, January 1, 2007

WM 06-0011, Wolf Creek Nuclear Operating Corporation Response to NRC Generic Letter 2006-

02, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power, March 31,

2006

Wolf Creek response to Generic Letter 96-06, January 29, 1997

Letter from Mel Gray, Subject: Request for Additional Information - Generic Letter 96-06,

Assurance of Equipment Operability and Containment Integrity during Design-Basis Accident

Conditions, June 18, 1999

NRC letter: Request for Additional Information Regarding Resolution of Generic Letter 2006-02,

Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power, December 3,

2006

A1-6 Attachment 1

CORRESPONDENCE

NRC letter: Revised Response Date for Request for Additional Information Regarding Resolution

of Generic Letter 2006-02, Grid Reliability and the Impact on Plant Risk and the Operability of

Offsite Power, December 13, 2006

NRC letter: Wolf Creek Generating Station - Closeout Letter for Generic Letter 2006-02, Grid

Reliability and the Impact on Plant Risk and the Operability of Offsite Power, May 10, 2007

NRC Information Notice 2007-01: Recent Operating Experience Concerning Hydrostatic Barriers

NRC Information Notice 2009-16: Spurious Relay Actuations Result in Loss of Power to

Safeguards Buses. (blue added 10-15-09)

NRC Regulatory Guide 1.101, Emergency Planning and Preparedness for Nuclear Power

Reactors, Revision 3

NEI 99-01, Methodology for Development of Emergency Action Levels, Revision 5

NRC Generic Letter 1989-13, Service Water System Problems Affecting Safety-Related

Equipment, January 29, 1990

LICENSEE EVENT REPORTS

NUMBER TITLE DATE

1995-006-00 Loss of Emergency Bus NB02 Due to Degraded Gasket December 7, 1995

on Motor Operator Cabinet

1995-006-01 Loss of Emergency Bus NB02 Due to Degraded Gasket February 1, 1996

on Motor Operator Cabinet

1999-005-00 Engineered Safety Features Actuation Because of Loss June 11, 1999

of Number 7 Transformer

2004-003-00 Automatic Start of B Emergency Diesel Generator Due May 5, 2004

To Start-Up Transformer Cable Ground Fault

2007-001-00 Emergency Diesel Out of Service Longer than Technical September 6, 2007

Specification Allowed Outage Time

2008-004-00 Loss of Offsite Power Event when the Reactor was

Defueled

ACTION PLAN DETAIL REPORTS

NUMBER TITLE DATE

1047 Actions for Switchyard Restoration Issues August 24, 2007

1100 SOER and Non-SOER Evaluation Guidance and SOER January 30, 2008

Effectiveness Reviews

1273 PIR 2007-003378 Action Plan - SOER Effectiveness February 20, 2008

Review

A1-7 Attachment 1

ACTION PLAN DETAIL REPORTS

NUMBER TITLE DATE

1703 CR 2007-004128 Corrective Actions May 13, 2009

1806 Critical Component Review of the Switchyard March 17, 2009

1890 EDG Alarm Acknowledge November 22, 2008

1909 CAP for CR 2008-001797 June 27, 2008

2032 CR 2008-001457 Action Plan February 27, 2009

2186 Revise AP 12-001 December 17, 2008

OPERABILITY EVALUATIONS

NUMBER TITLE REVISION

EF 09-007 Post ESFAS Water Hammer Evaluation 0

GK-08-004 Control Room AC Unit SGK04B and SGK05B Heat 0

Exchangers

OPERATING EXPERIENCE DETAIL REPORTS

NUMBER TITLE DATE

323 Information Notice 2007-14, Loss of Offsite Power and Dual- 9/20/2007

Unit Trip at Catawba Nuclear Generating Station

71 Information Notice 2006-06, Loss of Offsite Power and Station

Blackout are More Probably During Summer Period

WORK ORDERS

07-294733-000 08-302566-000 08-305239-000 08-305240-000 08-305244-000

08-305281-000 08-305289-000 08-305312-000 08-305312-001 08-305313-000

09-305434-001 09-305838-00 09316569-000 09-319476-000 09-320505-000

09-320505-001

HISTORY OF ESSENTIAL SERVICE WATER LEAKS

TIME DESCRIPTION FLOW VELOCITY, POSITION OF LEAK

FPS

2002 CCW HX drain leak, galvanic and under 0 Side of vertical pipe

deposit pitting

A1-8 Attachment 1

HISTORY OF ESSENTIAL SERVICE WATER LEAKS

TIME DESCRIPTION FLOW VELOCITY, POSITION OF LEAK

FPS

2005 SW discharge bypass line leak, under 0, Stagnant Bottom segment of pipe

deposit corrosion EA129HBC-16

2005 ESW - AFW leak, under deposit 0, Stagnant Bottom segment of pipe

corrosion EF054HBC-8

2007 SGN01D containment air cooler 6 return ~ 6.0 Side of vertical pipe

header, under deposit pitting

2009 ESW B 30 return line, through-wall pit 1.6 Bottom segment of pipe

EF138HBC-30

2009 ESW B 18 supply leak at weld 5.9 Weld area, side of pipe

EF150HBC-18

2009 ESW A 8 room cooler return line leak 0.9/1.6 Bottom segment of pipe

EF049HBC-8

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION / DATE

Posttrip Review Data Package August 19, 2009

Technical Specifications and Bases

Operating License

Control Room Logs August 19-26, 2009

Outage Center Logs August 19-26, 2009

Table 2-2 Offsite Dose Calculation Manual 6

Table 3-2 Offsite Dose Calculation Manual 6

WCAP-12231 Station Blackout Coping Assessment for Wolf Creek April 15, 1989

Generating Station

Safety Evaluation and Request for Additional Information January 16, 1992

Concurring Station Blackout Analysis for the Wolf Creek

Generating Station

Wolf Creek Generating Station - Supplemental Safety June 16, 1992

Evaluation Regarding the Stat ion Blackout Rule

DCP 07687 GE Magne-Blast Circuit Breaker Replacement 5

A1-9 Attachment 1

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION / DATE

Simplified Switchyard Drawing

Zone 117 Device List

Westinghouse Instructions for Metering Accuracy Capacitor June 1982

Voltage Transformer Type PCA-9

Wolf Creek Generating Station License Renewal Application 22

ACE Documents for CR 18785 September 21, 2009

2938 Information on ITIP: Response to NRC Information September 22, 2009

Notice 95-04

2507 Information on ITIP: Response to NRC Information September 22, 2009

Notice 93-83

2275 Information on ITIP: Response to NRC Information September 22, 2009

Notice 93-17

946 Information on ITIP: Response to NRC Information September 22, 2009

Notice 88-75

Switchyard SPV Evaluation

Switchyard SPVs and Mitigating Strategies

Switchyard Component IDs

Notes regarding CR 2008-001457

SER 4-06 INPO Significant Event Re port: Dual-Unit Loss of Off-Site September 25, 2006

Power

2898 CDE Detail Report: Extension Request for CR 2008-005913 May 13, 2009

DOBLE Test Assistant - Autotransfer without Tertiary

Bushing Analysis Test Data

12708 Engineering Disposition: Evaluation of ESW Water Hammer 1

Event Due to Loss of Offsite Power

Licensing Evaluation/Reportability Evaluation Request

2008-023/PIR 2008-001797

93 Operability/Reportability Detail Report November 21, 2008

Line loss spreadsheet March 6, 2004 through

A1-10 Attachment 1

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION / DATE

August 19, 2009

Westar Energy Root Cause Analysis Report: Root Cause March 30, 2009

Analysis Performed at Management Discretion

Incident Investigation Report 09-002 for CR 00019245 October 1, 2009

NRC Question 1, Request 12821

NRC Question 2, Request 12831

NRC Question 3, Request 12841

NRC Question 4, Request 12851

Modification Pipe Support Mod on GN Sys for Water Hammer 2

Package 05818

STN PE-040G Completed Surveillance of Transient Event Walkdown April 7, 2008

LR1007001 Emergency Action Levels and Protective Action

Recommendations Training Material

Updated Safety Analysis Report Section 3.9(N), Table

3.9 (N) - 13 Component Cyclic or Transient Limits

Table 4: Cycle Summary - Current Analysis Period -

11/1/07 through 8/18/08

WCAP 12231, Station Blackout Coping Assessment for Wolf April 15, 1989

Creek Generating Station

Computer Point Trend for Points ALF0002 and AEL0517 August 21, 2009

Change # 12798 Engineering Disposition Evaluation of Essential Service 1

Water Water Hammer Event due to Loss of Offsite Power

Simulator Training Performance Evaluation Summary for October 15, 2008

Crew - D

IIT 09-002 For Condition Report 00019245, Loss of Offsite Power and September 22, 2009

Plant Trip

Post Trip Review Data Package for October 7, 2004

Purchase Order 745187/0 for Engineering Services to March 18, 2009

Address Water Hammer Issues

A1-11 Attachment 1

UNITED STATES

NUCLEAR RE GULATO RY COM M I SSI ON

R EGI ON I V

612 EAST LAMAR BLVD, SUI TE 400

ARLIN GTON, TEXAS 76011-4125

MEMORANDUM TO: Richard Deese, Senior Project Engineer, Team Leader

Projects Branch B

Division of Reactor Projects

David Dumbacher, Senior Resident Inspector

Projects Branch B

Division of Reactor Projects

Jim Medoff, Senior Mechanical Engineer

Division of License Renewal

Office Nuclear Reactor Regulation

FROM: Dwight Chamberlain, Director

Division of Reactor Projects

SUBJECT: CHARTER FOR SPECIAL INSPECTION INVOLVING THE LOSS OF

OFFSITE POWER AND REACTOR TRIP AT WOLF CREEK

GENERATING STATION

In response to the loss of offsite power and subsequent reactor trip which occurred at Wolf

Creek Generating Station on August 19, 2009, a special inspection will be performed. You are

hereby designated as the special inspection team leader.

A. Basis

On August 19, 2009, during stormy weather in the area, Wolf Creek Generating Station

experienced a loss of all 345 kV power to its switchyard. All reactor coolant pumps,

condensate pumps and remaining secondary cooling equipment lost power resulting in

the inability to reject heat to the condenser. The main turbine tripped followed by a

reactor trip. With the condenser unavailable, cooling was supplied by the auxiliary

feedwater system and discharged through the atmospheric relief valves.

With offsite power unavailable, the emergency diesel generators started and powered

emergency loads as required.

Offsite power was noted to have numerous interruptions in the last year, with momentary

line outage occurring relatively frequently. The Rose Hill offsite power line experienced

brief or momentary line outages at least 7 times within the last year. Faulty equipment

on the Rose Hill line which failed to block the effects of the La Cygne line lighting strike

is believed to have led this loss of single offsite power line event into a complete loss of

offsite power.

A2-1 Attachment 2

Also the essential service water system experienced a through-wall leak concurrent with

the event. A 3/8-inch hole was revealed in the header leading to the emergency core

cooling system room coolers as water was discovered streaming from the essential

service water piping after the event. Further evaluation of the area around the hole

uncovered another adjacent area that was below minimum wall. These and previously

identified leaks lead to questioning the reliability of the essential service water system.

A regional Senior Reactor Analyst (SRA) preliminarily estimated the Incremental

Conditional Core Damage Probability for this issue to be 6.1 x 10-6, which falls in the

region which recommends a special inspection. A special inspection will be performed

since there are questions with the reliability of offsite power.

B. Scope

1. Develop a complete sequence of events related to the event.

2. To support review of the problem identification and resolution aspects of the

event:

a. Review operating experience involving prior opportunities to identify and evaluate

action implemented at Wolf Creek from industry Operating Experience.

b. Review the licensees root cause analysis for the event initiator and determine if

it was conducted to a level of detail commensurate with the significance of the

problem.

c. Determine if the licensees corrective actions have addressed the extent of

condition and assess whether these actions are adequate to prevent recurrence.

3. Perform the following to review the licensees offsite power system:

a. Review the licensees actions for prior instances of loss of the offsite power lines

and whether the licensees actions were commensurate with safety for the

number of previous line failures.

b. Assess the licensees ability to meet the General Design Criteria requirements for

independence of the offsite power lines in light of conditions surrounding the

event.

4. Perform the following to review the licensees essential service water system:

a. In light of the leak in the essential service water system that developed, review

the scope and depth of the licensees actions for the monitoring and prevention

of degradation of the essential service water system piping [extent of condition

check]. In this review, verify the licensees commitments to Generic Letter 89-13,

if applicable.

b. Review the licensees bases for insulating the essential service water piping in

the auxiliary building.

c. Review the application of ASME Code Case N-513-2, especially with regard to

choice and acceptability of the additional (extent of condition required by ASME

A2-2 Attachment 2

Code Case and others) ultrasonic testing samples performed for the identified

areas.

d. Evaluate the adequacy of the repairs to the 3/8-inch hole in the essential service

water pipe that occurred during the event and the subsequent below minimum

wall thickness area.

5. Perform the following to review the performance of plant systems during the

event:

a. Review the acceptability of the observed pressure oscillations observed on the

suction of the auxiliary feedwater pumps and their impact on system operability

and technical specifications.

b. Determine if reasonable evidence existed for deduction that a water hammer

event occurred in the essential service water system and whether licensee

actions following the event were sufficient for such an evaluation.

c. Review the design and operation of the internal flood control features in the plant,

in light of being able to handle a slightly larger leak during a sustained loss of

offsite power.

d. Determine if any of the radiation monitor failures experienced in the event would

have hampered further actions (i.e., implementing the emergency plan).

e. Review the actions taken for the loss of fire detection capability in the auxiliary

building during the event. Establish if this loss was anticipated in plant design.

6. Review the post-trip report for adequacy and whether the conclusions the

licensee drew are supported by the report.

7. Review the causes of the high level in Steam Generator A that occurred the day

after the event.

8. Verify the licensee met the proper reporting requirements of 10 CFR 50.72 and

10 CFR 50.73. Determine if the licensee has plans to issue a Licensee Event

Report to document this issue.

9. Review the licensees compliance with the Technical Specifications.

10. Review the licensees decision to maintain the plant in Mode 3 (feeding from the

condensate storage tank with auxiliary feedwater and dumping steam with the

atmospheric relief valves) for an extended period of time.

11. Determine if the licensee correctly applied the Emergency Action Levels and if

the Emergency Action Levels are appropriate.

12. Support assessment of risk significance by performing the following:

a. Collect facts to support an accurate portrayal of exposure time for the LOOP.

b. Collect facts to support proper crediting of the licensees ability to recover offsite

power sources within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as assumed in the risk assessment. Ensure to

A2-3 Attachment 2

include in the assessment the trouble annunciators that existed on the safety

transformers during the event.

c. Collect facts to support/refute crediting the licensees ability to recover offsite

power within 15 minutes in support of establishing low pressure recirculation for a

reactor coolant pump seal LOCA.

d. Collect facts to verify/refute classification as a grid-centered loss of offsite power

for risk assessment purposes.

e. Verify the risk assessment assumption that no test or maintenance were in

progress at the time of the event.

f. Collect facts to support the senior risk analysts in making a realistic assumption

of the unreliability of the essential service water system.

g. Determine if the difficulties experienced with the startup and main feed pumps on

the prior startup and the startup from this event represented a loss of mitigation

equipment.

h. Verify the function of the main steam isolation valve rupture discs was per design

and did not preclude use of any mitigation equipment when they ruptured.

C. Guidance

Inspection Procedure 93812, Special Inspection, will be used during this inspection. The

inspection should emphasize fact-finding in its review of the circumstance surrounding this

event. It is not the responsibility of the team to examine the regulatory process. Safety

concerns identified that are not directly to the event should be reported to the Region IV office

for appropriate action.

The team will report to the site and begin inspection no later than September 21, 2009. While

onsite, you will provide daily status briefings to Region IV management, who will coordinate with

the Office of Nuclear Reactor Regulation, to ensure that all other parties are kept informed.

Depending on the outcome of the inspection, inspection results will be documented in Special

Inspection Report 05000482/2009007. This report will be issued within 45 days of the

completion of the inspection.

This guidance may be modified should you develop significant new information that warrants

review. Should you require support for the final determination of the risk significance of any

issue, contact Michael Runyan at (817) 860-8142. Should you have any questions concerning

this guidance, contact Vince Gaddy at (817) 860-8141.

A2-4 Attachment 2

ATTACHMENT 3

NRC Technical Review of the August 19, 2009, Self-Revealing Flaw in Essential Service

Water System Piping

General Summary

The Wolf Creeks flaw evaluation is acceptable. The licensee used Code Case N-513-2, the

ASME Code Section XI, Appendix H, and ASME Code,Section III, ND-3600 to perform the flaw

evaluations. The licensee did not use information outside of the ASME Code (other than the

wear rate. (See questions # 4 and discussion below).

In accordance with N-513-2, the licensee will monitor the leakage each shift, perform UT of the

pinhole every 30 days, and perform UT at a minimum 10 locations. The licensee performed a

temporary repair (encapsulation) at the pinhole location and will perform a code repair in the

next refueling outage.

Suggested Questions to Ask the Licensee

1. On page 3 of 5 of the licensees engineering disposition paper, the licensee stated that

Engineering shall be notified of any changes in the leakage or flaw growth. This is an open

ended statement (not useful in terms of NRC regulatory/enforcement actions) because there is

no commitment in the licensees part as to what are the acceptance criteria for the leakage or

flaw growth or the corrective actions that they will do. It is not clear what the licensee would do

if there is a change in the leakage or if there is a flaw growth that extends outside the

encapsulation. It is not clear at what leak rate or flaw growth the licensee will take corrective

action. The licensee needs to clarify the specific acceptance criteria on leak rate and flaw

growth and discuss corresponding actions.

2. The licensee needs to clarify why they used the ASME Code,Section XI, Appendix H to

evaluate the flaw(s) instead of the ASME Code,Section XI, Appendix C, which is required by

Code Case N-513-2. [see the basis of this question below]

3. The licensee stated that it will perform augmented UT on 10 locations (on page 3 of 5 of the

Engineering report). However, it is not clear whether these 10 locations are in the same

degraded pipe or in sister pipes (or pipes in the same system). At a minimum, the licensee

needs to check the wall thickness of the degraded pipe to ensure that there are no other

locations in the pipe that have the corrosion problems. The licensee also needs to UT sister

pipes in the affected piping system. The licensee needs to clarify where are the 10 locations

that will be examined to satisfy the requirements of Code Case N-513-2, paragraph 5.0 [see

discussion below].

4. Appendix 2 of the licensees flaw evaluation calculates the wear rate of the pinhole. The

wear rate was calculated by dividing the difference between the nominal wall thickness (0.322)

and the final wall thickness (which is zero because of the pinhole) by the operating years. This

wear rate method assumes that general corrosion at the pinhole is directly proportional to the

operating time (i.e., a linear relationship) and that corrosion initiated from day one of the

commercial operation. The licensee needs to justify the linear relationship for the wear rate.

[See discussion below]

A3-1 Attachment 3

Discussions

Appendix 1 of the licensees flaw evaluation---

In Appendix 1 of the licensees flaw evaluation, the licensee back-calculated the allowable pipe

thickness based on the stress equations in ASME Code,Section III, ND-3600 with various load

combinations and associated allowable stresses. Using this approach, the licensee calculated

the minimum pipe wall thickness.

The summary page of Appendix 1 shows the minimum thickness for each piping load

combination. The allowable thickness ranges from 0.0035 inches to 0.0595 inches, depending

on the load combinations. The nominal wall thickness is 0.322 inches. The licensee selected

the allowable thickness of 0.1 inches. This is conservative because it is more than the

calculated wall thickness (> 0.0595). If the pipe wall thickness falls below 0.1 inches, the pipe

does not meet the Section III code allowable, does not meet the design conditions, and is,

therefore, inoperable.

The wall thickness at the pinhole location is zero and is below the allowable thickness of 0.1

inches. However, the licensee has used Code case N-513-2 to accept the structural integrity of

the pipe considering the pinhole location (i.e., operable but degraded).

I do not know if the licensee has performed wall thickness measurement on various locations of

the leaking pipe to confirm that the rest of the leaking pipe satisfies the allowable thickness of

0.1 inches. Question # 3 above should confirm this issue.

Appendix 2 of the licensees flaw evaluation

Appendix 2 calculates the wear rate of the pinhole. The wear rate was calculated by dividing

the difference between the nominal wall thickness (0.322) and the final wall thickness (which is

zero because of the pinhole) by the operating years (20 years). This method assumes that

general corrosion at the pinhole is directly proportional to the operating time (i.e., a linear

relationship) and that corrosion initiated from day one of the commercial operation. I do not

know if this linear relationship for the wear rate is correct. In addition, if the inside of the pipe is

coated with epoxy or some protective coating then the corrosion will not initiate until some years

later. If the pipe is not coated inside, it will still take a few years before corrosion initiates. If the

corrosion initiates not from day one but started several years later, the denominator in the above

wear rate equation will be less than 20 year. This will make the wear rate higher and more

conservative. The licensees wear rate may not be conservative because it assumes the

corrosion starts on day one of the commercial operation. The licensee needs to justify its

method of wear rate calculation. [note that N-513-2 does not specify the flaw growth rate for

general corrosion. The flaw growth rate in N-513-2 is for planar flaws which is not applicable to

general corrosion in service water line at wolf creek. Therefore, there is no requirement for the

licensee to use certain wear rate method. All we can do is to ask why they think their method is

acceptable]

Appendices 3 and 4 of the licensees flaw evaluation--

Appendices 3 and 4 analyze the general corrosion/pinhole (which is a nonplanar flaw) as two

planar flaws to show that the pipe with the 2 planar flaws has sufficient fracture toughness to

resist catastrophic failure. Code Case N-513-2, paragraph 3.0(f) allows evaluating a through

wall penetration as two independent planar flawsaxial flaw and circumferential flaw. Appendix

A3-2 Attachment 3

3 of the licensees flaw evaluation evaluates the axial flaw. Appendix 4 of the licensees flaw

evaluation evaluates the circumferential flaw.

Appendices 3 and 4 use information in Section XI, Appendix H instead of Section XI, Appendix

C, which is required by Code Case N-513-2. Code Case N-513-2, paragraph 3.0(c) requires

that for planar flaws in ferritic piping the evaluation procedure of ASME Section XI Appendix C

be used and N-513-2 cites several Appendix C subparagraphs. However, the cited Appendix C

paragraphs do not appear in the 1998 Section through 2000 addenda of the ASME Code,

Section XI, which I suppose is the code of record for Wolf Creek for the current ISI inspection

interval. Therefore, I believe that the licensee used Appendix H of the Section XI to perform the

flaw evaluation because Appendix C in the 1998 edition of the ASME Code, section XI, does not

contain flaw evaluation information that is required by N-513-2.

I have no problem with the licensee using the ASME Code,Section XI, Appendix H for its flaw

evaluation.

Appendix 3 demonstrates that the leaking pipe will not fail catastrophically because the

calculated stress intensity factor (Kmax) of the axial flaw (pinhole) is less than the stress

intensity factor of the pipe material (Kicallowable).

Appendix 4 demonstrates that the leaking pipe will not fail catastrophically because the

calculated stress intensity factor (Kmax) of the circumferential flaw (pinhole) is less than the

stress intensity factor of the pipe material (Kicallowable).

A3-3 Attachment 3