IR 05000482/2011004

IR 05000482-11-004, 07/01/2011 9/30/2011; Wolf Creek Generating Station, Integrated Resident Report, Equipment Alignment, Fire Protection, Surveillance Testing, and Event Followup

ML113140484
Person / Time
Site:	Wolf Creek
Issue date:	11/10/2011
From:	Geoffrey Miller NRC/RGN-IV/DRP/RPB-B
To:	Matthew Sunseri Wolf Creek
References
IR-11-004
Download: ML113140484 (54)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGI ON I V 612 EAST LAMAR BLVD, SUITE 400 ARLINGTON, TEXAS 76011-4125 November 10, 2011 Matthew Sunseri, President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation P.O. Box 411 Burlington, KS 66839 Subject: WOLF CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000482/2011004

Dear Mr. Sunseri:

On September 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Wolf Creek Generating Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on October 5, 2011, and again on November 10, 2011, with Mr. S. Hedges, Site Vice President, and other members of your staff.

The inspections examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

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

Based on the results of this inspection, the NRC has identified four issues that were evaluated under the risk significance determination process as having very low safety significance (Green). The NRC determined that violations are associated with three of these issues.

Additionally, four licensee-identified violations were determined to be of very low safety significance and are listed in this report. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as a noncited violations, consistent with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the violation or the significance of the noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.

20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the

Wolf Creek Nuclear Operating Corporation -2-NRC Resident Inspector at the facility. In addition, if you disagree with the crosscutting aspect assigned to 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 at the facility.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure(s), and your response, if you choose to provide one for cases where a response is not required, will be made available electronically for public inspection in the NRC Public Document Room or from the NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response should not include any personal privacy or proprietary information so that it can be made available to the Public without redaction.

Sincerely,

/RA/

Geoffrey B. Miller, Chief Project Branch B Division of Reactor Projects Docket No. 50-482 License No. NPF-42

Enclosure:

NRC Inspection Report 05000482/2011004 w/Attachment: Supplemental Information

REGION IV==

Docket: 05000482 License: NPF-42 Report: 05000482/2011004 Licensee: Wolf Creek Nuclear Operating Corporation Facility: Wolf Creek Generating Station Location: 1550 Oxen Lane NE Burlington, Kansas Dates: July 1 to September 30, 2011 Inspectors: C. Long, Senior Resident Inspector C. Peabody, Resident Inspector L. Carson, Senior Health Physics L. Willoughby, Senior Project Engineer J. Bashore, Resident Inspector, Palo Verde N. Makris, Project Engineer S. Alferink, Reactor Inspector Approved By: G. Miller, Chief, Project Branch B, Division of Reactor Projects-1- Enclosure

Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

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

DRP Director (Kriss.Kennedy@nrc.gov)

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

DRS Director (Anton.Vegel@nrc.gov)

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

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

Resident Inspector (Charles.Peabody@nrc.gov)

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

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

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

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

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

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

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

Project Manager (Randy.Hall@nrc.gov)

Branch Chief, DRS/TSB (Dale.Powers@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

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

Senior Health Physics, PSB2 (Lewis.Carson@nrc.gov)

OEMail Resource Inspection Reports/MidCycle and EOC Letters to the following:

ROPreports Only inspection reports to the following:

RIV/ETA/OEDO (Mark.Franke@nrc.gov)

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

R:\_REACTORS\_WC\2011\WC2011-004-CML.docx ML113140484 ADAMS: No Yes SUNSI Review Complete Reviewer Initials: RWD Publicly Available Non-Sensitive Non-publicly Available Sensitive SRI:DRP/B RI:DRP/B C:DRS/EB1 C:DRS/EB2 C:DRS/OB CLong CPeabody TFarnholtz NOKeefe MHaire

/RA/ /RA/ /RLatta for/ /RA/ /RA/

11/10/2011 11/9/2011 11/7/2011 11/7/2011 11/7/2011 C:DRS/PSB1 C:DRS/PSB2 C:DRP/B MHay GWerner GMiller

/RA/ /RA/ /RA/

11/7/2011 11/7/2011 11/10/2011 OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax-2- Enclosure

SUMMARY OF FINDINGS

IR 05000482/2011004, 7/1 - 9/30/2011; Wolf Creek Generating Station, Integrated Resident

Report, Equipment Alignment, Fire Protection, Surveillance Testing, and Event Followup.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Three 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 Inspection Manual Chapter 0609, Significance Determination Process. The crosscutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross Cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

The inspectors identified a finding involving degraded switchyard equipment that caused a loss of offsite power. On August 19, 2009, carrier system signal failures allowed a lightning strike to cause a loss of all three 345 kV lines. This issue is captured in the corrective action program as Condition Report 19245. Wolf Creek and its owner companies have upgraded all capacitive coupled voltage transformers, added fault data recorders, added enhanced line checking procedures with the grid operator, regrounded all three 345 kV lines, and planned to add an offsite power technical requirements manual limiting condition of operation per Condition Report 43244.

The issue is more than minor because it impacted the protection against external factors attribute of the Initiating Events Cornerstone 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 Inspection Manual Chapter 0609.04, inspectors screened the finding to Phase 3 because it caused both a reactor trip and loss of mitigation equipment or functions to not be available. The senior reactor analyst calculated that the increase in core damage frequency was 2.6 x 10-7, which was of very low safety significance (Green). The inspectors determined that no crosscutting aspects applied because this finding is not indicative of current licensee performance (Section 1R04).

Green.

The inspectors reviewed a noncited violation of Technical Specification 5.4.1.a, Procedures, for failure of operators to follow procedure to maintain steam generator water level. This failure resulted in level in steam generator B level lowering such that a Lo Lo level actuation was initiated, which isolated normal feedwater and initiated auxiliary feedwater. A reactor trip signal was also received, but the control rods were already tripped. The licensee captured this issue in their corrective action program as Condition Report 39732 and subsequently changed its operating procedures and conducted remediation training of licensed operators.

The issue was considered more than minor because it impacted the human performance attribute of the Initiating Events Cornerstone and its objective to limit the events that upset plant stability and challenge safety systems during power and shutdown operations. Using Inspection Manual Chapter 0609.04, the inspectors determined the finding to be of very low safety significance (Green)because the finding did not contribute to both the likelihood of a reactor trip and the loss of mitigation equipment. The inspectors determined that the finding has a crosscutting aspect in the area of human performance associated with the decision making component because the decision by the crew to maintain steam generator level in a difficult to maintain band proved to have unintended consequences H.1.b] (Section 4OA3).

Cornerstone: Mitigating Systems

Green.

The inspectors identified a noncited violation of 10 CFR 50.55a, Codes and Standards, when the licensee failed to correctly test a series of butterfly valves. The licensee installed seven Crane butterfly valves in the essential service water system in 2000 and 2002 but did not perform a preservice test under conditions as close as possible to the inservice test conditions or develop and perform an inservice stroke test under conditions as close to design basis conditions as required by their applicable code case. This issue is captured in the corrective action program as Condition Report 44218.

The issue is more than minor because it impacted the Mitigating Systems Cornerstone objective to ensure that to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, the finding was determined to be of very low safety significance (Green) because the finding is not a design or qualification deficiency confirmed not to result in loss of operability or functionality; the finding does not represent a loss of system safety function; the finding does not represent actual loss of safety function of a single train for more than its technical specification allowed outage time; the finding does not represent an actual loss of safety function of one or more nontechnical specification trains of equipment designated as risk significant per 10 CFR 50.65 for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and the finding does not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors did not assign a crosscutting aspect because the finding was not indicative of current performance (Section 1R22).

Cornerstone: Emergency Preparedness

Green.

The inspectors identified a noncited violation of 10 CFR 50.47,

Emergency Plans, for the failure to maintain an adequate emergency facility.

The technical support center doors were propped open during maintenance for 82 days without a breach permit, leaving the licensee with no procedural controls to maintain the ability of the technical support center to withstand the 100-year recurrence winds as designed. The licensees procedures would have caused operations personnel to review breaches and shut doors for a tornado event.

This issue is captured in the corrective action program as Condition Report 42495.

The issue was more than minor because it impacted the facilities and equipment attribute of Emergency Preparedness Cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The inspectors used the emergency preparedness significance determination process and determined that the finding was Green because changes were made to the technical support center that did not comply with the plan and did not have compensatory actions, but the facility remained functional. The inspectors found that the cause of the finding had a crosscutting aspect in the area of human performance associated with the resources component, in that the breach procedure was not consistent with the design of the technical support center and resulted in missed compensatory action H.2.c] (Section 1R05).

Licensee-Identified Violations

Violations of very low safety significance, which were identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and condition report numbers are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

Wolf Creek began the quarter at eight percent power. From July 1 to July 6, Wolf Creek remained at 58 percent power for main feedwater pump troubleshooting. From July 6 to July 7, Wolf Creek reduced power to 48 percent to remove main feed pump B from service for circuit card replacement and to monitor those replacements. On July 9, Wolf Creek achieved full power. On August 14, Wolf Creek received enforcement discretion to not shutdown for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> pending completion of repairs to the turbine-driven auxiliary feedwater pump. On August 15, Wolf Creek reduced power to 87 percent when the turbine-driven auxiliary feedwater pump was not complete. Wolf Creek returned to 100 percent power on August 15 after the turbine-driven auxiliary feedwater pump was declared operable. Wolf Creek remained at 100 percent power for the remainder of the quarter.

REACTOR SAFETY

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

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

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

• July 1, 2011, Vital batteries - during charger maintenance

• August 12, 2011, Motor-driven auxiliary feedwater A and B while turbine-driven auxiliary feedwater out of service

• August 17, 2011, STS NB-005, Offsite power and startup transformer breaker alignment

• September 7, 2011, Residual heat removal train B partial alignment for safety injection standby condition The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report (USAR), technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in

order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four partial system walkdown sample as defined in Inspection Procedure 71111.04-05.

a. Findings

Introduction.

On July 21, 2011, the inspectors identified a Green finding for degraded switchyard components that caused a loss of offsite power.

Description.

On August 19, 2009, Wolf Creek experienced a loss of offsite power when lightning struck the 345 kV LaCygne line. Latent deficiencies in the Wolf Creek 345 kV substation and remote switchyards it communicates with caused the lightning to open circuit breakers for the LaCygne and Benton lines. Wolf Creek did not enter any technical specification action statements for offsite power. After discussion with the inspectors, control room operators entered Technical Specification 3.8.1, conditions D.1 and D.2, for two offsite sources inoperable at 3:49 p.m. Surveillance Procedure STS NB-005 could not be completed because the 4 kV safety buses were being powered from the emergency diesel generators, not offsite power. After control room operators restored offsite power to the vital buses and secured the diesel generators, Technical Specification 3.8.1, actions D.1 and D.2 were exited.

The carrier communications equipment malfunctioned due to the failure of a capacitive coupled voltage transformer in the Rose Hill substation. Also, a wave trap in the Wolf Creek switchyard was out of tune. Wolf Creek and its owner companies later found that the coupling capacitor voltage transformer had been damaged for a significant period of time prior to August 19, 2009.

The inspectors reviewed the Wolf Creek root cause evaluation. The inspectors found that the carrier system signal failure that allowed a fault to open the breakers to the other two 345 kV lines was inconsistent with the USAR design. The blocking carrier signal that failed occurred inside the Wolf Creek substation because of problems with the Wolf Creek side of the Rose Hill lines wave trap. Hardware failure analysis of the capacitive coupled voltage transformer found that the low voltage side had a failed nylon mounting rod that allowed a discharge resistor to slump until it started arcing until it failed. The arcing interfered with operation of the blocking function. The hardware failure analysis found that the nut at the base of the nylon rod was likely over tightened during assembly causing it to crack under tension with the flaw growing across the diameter of the rod

due to thermal aging over several years. The failure analysis found the failed discharge resistor was not consistent with a lightning strike and instead more likely occurred over several years. The Rose Hill line breaker cycling due to lightning the morning of August 19 did not involve the blocking signal that later failed on August 19. Wolf Creek provided data that breakers opening on August 10, 2011, on the LaCygne line provided data that the blocking function, which keeps the other lines breakers closed during a momentary fault, functioned correctly.

Wolf Creeks root cause evaluation found that Condition Report 7499, regarding the September 2007 switchyard and grid review, described the aging of capacitive coupled voltage transformer. Significant operating experience from outside organizations on replacement of aging coupling capacitor voltage transformers and performance of preventive maintenance, including internals inspections, was not acted upon. An internal inspection would have identified the loose discharge resistor inside the Rose Hill coupling capacitor voltage transformers. Wolf Creek identified that no age-related replacement program existed. Testing was performed upon installation. The only preventive maintenance was to change fuses every 2 years. Capacitive coupled voltage transformer were considered run-to-failure components. Condition Report 7499 had not been evaluated nor had corrective actions been developed at the time of the August 2009 event. The automated carrier signal checks (blocking signal checks) would not have returned an error for the failures, depending on the amount of arcing in the coupling capacitor voltage transformers. There was no failure analysis for the wave trap.

The spark gap was replaced, a different tuning connection was utilized and the wave trap re-tested satisfactorily. Lastly, Wolf Creeks root cause evaluation found a significant trend of 345 kV line losses and unplanned breaker openings that did not receive condition reports. Line losses that did receive condition reports did not result in action to determine causes other than breakage of equipment (i.e. broken 345 kV tower cross arms). The inspectors concluded that the issue was within Wolf Creeks ability to foresee and correct based on the operating experience.

Analysis.

The failure to maintain 345 kV equipment such that a single line fault could be cleared without affecting the other lines, as described in the USAR was a performance deficiency. The issue is more than minor because it impacted the protection against external factors attribute of the Initiating Events Cornerstone 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 Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, inspectors screened the finding to Phase 3 because the finding caused both a reactor trip and loss of mitigation equipment or functions to not be available. As a bounding evaluation, the senior reactor analyst assumed that the change in core damage frequency (CDF) was approximately equal to the conditional core damage probability (CCDP) for a switchyard-centered loss of offsite power over the exposure period (EXP). Using the Wolf Creek Station Standardized Plant Analysis Risk Model, Revision 8.15, the analyst quantified this value as 1.054 x 10-5/year. The exposure period was determined to be from the last successful operation of the capacitive coupled voltage transformer on August 10, 2009, until the failure of the blocking function on August 19, 2009. The analyst determined that the entire period should be used because

the capacitive coupled voltage transformer was most likely in a condition to fail with the next demand following its actuation on August 10. Therefore, the analyst calculated the change in risk as follows:

CDF = CCDP

• EXP

= 1.054 x 10-5/year ÷ 365 days/year

• 9 days

= 2.6 x 10-7 The value of 2.6 x 10-7 corresponds to a finding of very low safety significance (Green).

In accordance with the guidance in Inspection Manual Chapter 0609, Appendix H, Containment Integrity Significance Determination Process, this finding would not involve a significant increase in risk of a large, early release of radiation because Wolf Creek has a large, dry containment and the dominant sequences contributing to the change in the core damage frequency did not involve either a steam generator tube rupture or an inter-system loss of coolant accident. The inspectors determined that no crosscutting aspects applied because this finding is not indicative of current licensee performance.

Enforcement.

No violation of regulatory requirements occurred because the switchyard is not safety related. Because this issue is of very low significance and it is entered into the corrective action program as Condition Report 19245, this issue is being treated as a Finding in accordance with Section 2.3.2 of the NRC Enforcement Policy:

FIN 05000482/2011004-01, Switchyard Component Failures Cause Loss of Ring Bus and Loss of Offsite Power.

1R05 Fire Protection

.1 Quarterly Fire Inspection Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns that were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• July 20, 2011, Electro-hydraulic control skid turbine building 2000

• July 21, 2011, Main feedwater turbine building 2034

• July 21, 2011, Main turbine/generator turbine building 2065

• August 10, 2011, Technical support center The inspectors reviewed these areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features in accordance with the

licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four quarterly fire-protection inspection samples as defined in Inspection Procedure 71111.05-05.

b. Findings

Introduction.

On August 10, 2011, the inspectors identified a Green noncited violation of 10 CFR 50.47, Emergency Plans, when technical support center doors were propped open without a breach permit. Without a permit, operators would not be alerted to shut the doors during a severe weather event.

Description.

On August 10, 2011, the inspectors identified that no door breach permit was utilized for propping open door number Z015009. This door is between the technical support center mechanical room and the outside. The mechanical room contains power supplies for the plant computer and the heat, ventilation, and air conditioning system for the technical support center. Both are key to technical support center functionality. The heating, ventilation, and air conditioning is necessary to minimize radiation dose to technical support personnel during accidents. On June 1, 2011, the licensee discovered a fuel oil-to-coolant leak on the technical support center diesel generator. On June 3, 2011, work order 11-341781-003 was used to install a temporary technical support center diesel generator. Door Z015009 was propped open to allow temporary diesel electrical cables to tie into the permanent diesels generator output lugs. The door was tied open with rope and the entry was taped with sheet plastic to keep the interior air conditioned. This condition existed until August 24, 2011, when the permanent diesel was repaired and doors were shut.

The inspectors found that step 6.4.2 of Procedure AP 06-002, Radiological Emergency Response Plan, states that the technical support center is rated to withstand the 100-year recurrence winds. The inspectors noted that the ability of the technical support center to withstand these conditions could be challenged with the door open and questioned the licensee what controls or analysis existed to support the existing configuration. The inspectors did not find a breach permit tracking the doors and found that Procedure AP 10-104 Breach Authorization, stated that door Z015009 did not require a breach permit. The inspectors judged that Procedure AP 10-104 was inadequate because it did not protect equipment or facilities important to the

implementation of the emergency plan. Had a breach permit been in effect during a tornado, door Z015009 would have been shut since Off Normal Procedure OFN SG-003, Natural Events, would have called for operations to review breach permits and take action, as necessary, to shut doors. The inspectors did not find any other procedure that would remove the cables and shut the door due to any lesser severe weather.

Analysis.

The failure to ensure that the technical support center met step 6.4.2 of the emergency response plan was a performance deficiency. The issue was more than minor because it impacted Emergency Preparedness Cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, it impacted the facilities and equipment attribute. The inspectors used Section 4.8 of Inspection Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process, and determined that the finding was Green. Specifically, changes were made to the technical support center that did not comply with the emergency plan and no compensatory actions were taken, but the facility remained functional. The inspectors found that the cause of the finding had a crosscutting aspect in the area of human performance associated with the resources component, because the breach procedure was not consistent with the design of the technical support center and resulted in missed compensatory action H.2.c].

Enforcement.

Title 10 CFR 50.54(q), states, in part, that a holder of a nuclear power reactor operating license shall follow and maintain, in effect, emergency plans which meet the standards in 10 CFR 50.47(b). Title 10 CFR 50.47(b)(8) requires, in part, that adequate emergency facilities for emergency response be provided and maintained.

Step 6.4.2 of Procedure AP 06-002, Radiological Emergency Response Plan, states that the technical support center is rated to withstand the 100-year recurrence winds.

Contrary to the above, from June 3 to August 24, 2011, Wolf Creek did not maintain adequate emergency response facilities when it propped open an outer door of the technical support center without a breach permit which would have negatively impacted the facility. Because this finding is of very low safety significance and was entered into the licensee corrective action program as Condition Report 42495, this violation is being treated as a noncited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000482/2011004-02, Technical Support Center External Door Propped Open without Impairment.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the USAR, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding; reviewed the corrective action program to determine if licensee personnel identified and corrected flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. The inspectors also inspected the areas listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals,

watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers. Specific documents reviewed during this inspection are listed in the attachment.

• May 13, 2011, Manhole 301, No. 7 transformer output

• September 28, 2011, Rooms 3301/3302, 2000 engineered safety features switchgear rooms

• September 29, 2011, Rooms 1206/1207 - 1988 auxiliary feedwater These activities constitute completion of three flood protection measures inspection sample and one bunker/manhole sample as defined in Inspection Procedure 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Inspection Scope

On September 21, 2011, the inspectors observed a crew of licensed operators in the plants simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems; and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications

• Compliance with assumptions for manual action timing in Chapter 15 of the USAR The inspectors compared the crews performance in these areas to pre-established operator action expectations and successful critical task completion requirements.

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

These activities constitute completion of one quarterly licensed-operator requalification program sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk significant systems:

• Steam generator atmospheric relief valves The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

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

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

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

• Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective

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

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed licensee personnel's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• July 5, 2011, Main feedwater pump B trip on June 30, 2011

• July 21-24, 2011 Electro hydraulic control 125 V dc ground troubleshooting

• August 13, 2011, Battery charger NK-25 out of service

• August 14, 2011, Risk actions for turbine-driven auxiliary feedwater out of service during its associated notice of enforcement discretion

• August 31 to September 1, 2011, Essential service water A strainer flange leak The inspectors selected these activities based on potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five maintenance risk assessments and emergent work control inspection sample as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Leaking mid-loop transmitter valves as adequate boundary

• Technical Specification 3.0.3 entry for component cooling water system voiding

• Operation with pressurizer backup heaters normally energized The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and USAR to the licensee personnels evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three operability evaluations inspection samples as defined in Inspection Procedure 71111.15-04.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Temporary Modifications

a. Inspection Scope

• TMO-025-FC-00 Main feedwater pump monitoring equipment To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the temporary modification identified as TMO-025-FC-00, main feed pump monitoring equipment.

The inspectors reviewed the temporary modification and the associated safety-evaluation screening against the system design bases documentation, including the USAR and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed on the affected equipment, and licensee personnel evaluated the combined effects on mitigating systems and the integrity of radiological barriers.

These activities constitute completion of one sample for temporary plant modifications as defined in Inspection Procedure 71111.18-05.

b. Findings

No findings were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

The inspectors reviewed the following postmaintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• March 3, 2011, Valve EF-HV25 after yoke repair

• August 24, 2011, Technical support center diesel after head and injector replacement

• September 1, 2011, Emergency diesel generator A hunting during surveillance and margin test

• September 8, 2011, Replace manual control room ventilation isolation signal input buffer module train B

• September 13, 2011, Component cooling water B area cooler

• September 21, 2011, Temporary diesel-driven fire pump The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following (as applicable):

• The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed

• Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate The inspectors evaluated the activities against the technical specifications, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with postmaintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of six postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the USAR, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method supported operability or functionality

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME code requirements

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for restoring systems, structures, and components not meeting acceptance criteria were correct

• Reference setting data

• Annunciator and alarm setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing. The following surveillance testing was observed:

• March 7, 2011, Inservice testing of valve EF HV-025

• March 12, 2011, Emergency diesel generator A endurance test

• June 15, 2011, Inservice testing of component cooling water pump D

• June 23, 2011, Inservice testing of centrifugal charging pump A

• July 28, 2011, Reperformed reactor coolant system leak rate test in response to previous reactor coolant system leak rate test Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five surveillance testing inspection samples as defined in Inspection Procedure 71111.22-05.

b. Findings

Introduction.

On September 14, 2011, the inspectors identified a Green noncited violation of 10 CFR 50.55a(f)(6) when Wolf Creek failed to correctly test a series of butterfly valves.

Description.

Wolf Creek adopted ASME code case OMN-1 in 1998. Use of this code case allowed monitoring of valves using parameters other than stroke time. Valves EF HV-24, 25, 26, 39, 40, 41, and 42 are 30-inch diameter motor-operated Crane butterfly valves that were installed in October 2000 and March 2002. These valves are normally open and receive a shut signal to isolate service water from essential service water for various design basis events. The valves are required to shut against a 172 psi differential pressure for the design basis accident events.

The inspectors reviewed valve testing and found only valve EF HV-42 was tested under dynamic conditions (flow through the pipe) but did not include data acquisition on pipe pressures. It was a postmaintenance test for installation of the valve. Other tests were conducted under static flow conditions during refueling outages. Valve stem torque data was collected for these tests. The inspectors found that these tests essentially only tested valve packing friction, which was within acceptable limits. Without a differential pressure due to flow in the essential service water pipe, the valve bearings experience less friction and valve stem torque data does not effectively monitor valve condition.

Also, the flow of water opposes and assists the closing of the valve depending on disc position. Although not required by Wolf Creek procedures, valve engineers do examine valve torque traces against other identical valves to look for deviations in valve performance. Valve parameters such as stem torque and motor amperages were recorded with acceptable limits, but they do not approach any design values due to the static test.

The inspectors reviewed valve testing requirements and found that OMN-1, Sections 3.1 and 3.2 were not implemented. Section 3.1, Design Basis Verification Test, requires a test as close to design basis conditions as practicable for each motor-operated valve.

Section 3.2, Preservice Test, required a test under conditions as close as practicable to design basis conditions. The data from Sections 3.1 and 3.2 are to be used as the basis to evaluate inservice testing data. Data collected prior to implementation of the code case is acceptable, but the inspectors found no data for these valves. These Crane butterfly valves were installed after Generic Letters 89-10 and 96-05 were closed out by NRC inspections. There was not a prior Generic Letter 89-10 testing basis for these valves. The inspectors reviewed motor-operated valve sizing calculations and found substantial margin to the design basis conditions. Valves tested under static conditions have demonstrated consistent stem torque values over the past several years.

Analysis.

The failure to implement code case OMN-1 for essential service water valves is a performance deficiency. The issue is more than minor because it impacted the Mitigating Systems Cornerstone objective to ensure that to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Using Inspection Manual

Chapter 0609.04, the finding was determined to be of very low safety significance (Green) because the finding is not a design or qualification deficiency confirmed not to result in loss of operability or functionality; the finding does not represent a loss of system-safety function; the finding does not represent actual loss of safety function of a single train for more than its technical specification allowed outage time; the finding does not represent an actual loss of safety function of one or more nontechnical specification trains of equipment designated as risk significant per 10 CFR 50.65 for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and the finding does not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors did not assign a crosscutting aspect because the 2000 valve modification testing practices were not indicative of current performance.

Enforcement.

Title 10 CFR, 50.55a(f), Codes and Standards, requires, in part, that testing of safety-related valves meet the requirements of the ASME code. Wolf Creek adopted code case OMN-1 for valve testing. Section 3.1 of OMN-1 requires, in part, a test for each motor-operated valve under conditions as close as practicable to design-basis conditions. Section 3.2 of OMN-1 requires, in part, that a preservice test be conducted as close to inservice testing conditions as practicable. On October 17, 2000, Wolf Creek replaced a series of essential service water valves. Contrary to the above, from October 17, 2000, to the present, Wolf Creek has not performed a test under conditions as close as practicable to design basis or preservice conditions for motor-operated valves EF HV-23, -24, -25, -26, -39, -40, and -41. Because this finding is of very low safety significance and was entered into the licensee corrective action program as Condition Report 44218, this violation is being treated as a noncited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000482/2011004-03, Failure to Follow ASME Code Case OMN-1 for Butterfly Valves.

1EP6 Drill Evaluation

.1 Training Observations

a. Inspection Scope

The inspectors observed a simulator training evolution for licensed operators on September 20, 2011, which required emergency plan implementation by a licensee operations crew. This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the corrective action program. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.06-05.

b. Findings

No findings were identified.

2RS0 4 Occupational Dose Assessment

a. Inspection Scope

This area was inspected to:

(1) determine the accuracy and operability of personal monitoring equipment;

(2) determine the accuracy and effectiveness of the licensees methods for determining total effective dose equivalent; and

(3) ensure occupational dose is appropriately monitored. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items:

• External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters

• The technical competency and adequacy of the licensees internal dosimetry program

• Adequacy of the dosimetry program for special dosimetry situations such as declared pregnant workers, multiple dosimetry placement, and neutron dose assessment

• Audits, self-assessments, and corrective action documents related to dose assessment since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.04-05.

b. Findings

No findings were identified.

2RS0 5 Radiation Monitoring Instrumentation

a. Inspection Scope

This area was inspected to verify the licensee is assuring the accuracy and operability of radiation monitoring instruments that are used to:

(1) monitor areas, materials, and workers to ensure a radiologically safe work environment; and

(2) detect and quantify radioactive process streams and effluent releases. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance.

During the inspection, the inspectors interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items:

• Selected plant configurations and alignments of process, postaccident, and effluent monitors with descriptions in the USAR and the offsite dose calculation manual

• Select instrumentation, including effluent monitoring instrument, portable survey instruments, area radiation monitors, continuous air monitors, personnel contamination monitors, portal monitors, and small article monitors to examine their configurations and source checks

• Calibration and testing of process and effluent monitors, laboratory instrumentation, whole body counters, postaccident monitoring instrumentation, portal monitors, personnel contamination monitors, small article monitors, portable survey instruments, area radiation monitors, electronic dosimetry, air samplers, and continuous air monitors

• Audits, self-assessments, and corrective action documents related to radiation monitoring instrumentation since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.05-05.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the licensee for the 2nd Quarter 2011 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Emergency ac Power System (MS06)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - emergency ac power system performance indicator for the period from the 4th quarter 2010 to the 2nd quarter 2011, or October 1, 2010, through June 30, 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of 4th quarter 2010 to 2nd quarter 2011, or October 1, 2010, through June 30, 2011, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one mitigating systems performance index -

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

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - high pressure injection systems performance indicator for the period from the 4th quarter 2010 to 2nd quarter 2011, or October 1, 2010, through June 30, 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of 4th quarter 2010 to 2nd quarter 2011, or October 1, 2010, through June 30, 2011, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one mitigating systems performance index -

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

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for the period from the 4th quarter 2010 to 2nd quarter 2011, or October 1, 2010, through June 30, 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of 4th quarter 2010 to 2nd quarter 2011, or October 1, 2010, through June 30, 2011, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the

performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one mitigating systems performance index -

cooling water system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of various baseline inspections discussed in previous sections, the inspectors reviewed issues to verify that they were being entered into the Wolf Creek corrective action program at an appropriate threshold. The inspectors verified the program to be addressing issues in a timely manner as well as identifying and correcting adverse trends. The inspectors reviewed attributes that included:

• Complete and accurate identification of the problem

• Timely correction, commensurate with the safety significance

• Evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews

• Classification, prioritization, focus, and timeliness of corrective actions.

Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

These reviews for the identification and resolution of problems did not constitute any additional inspection samples. They were considered a part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

The inspectors performed a daily screening of items entered into the licensees corrective action program through review of the Wolf Creeks daily corrective action documents.

The inspectors performed these daily reviews as part of their plant status monitoring activities and did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Operation with Pressurizer Backup Heaters Normally Energized

a. Inspection Scope

The inspectors reviewed the continuing resolution of a long standing design issue of reactor operation on variable pressurizer heaters only with backup heaters in automatic.

Since original construction, Wolf Creek does not control reactor pressure using the variable heaters alone because they are insufficient to respond to pressure transients which occur during steady state power operations. Wolf Creek has created a workaround to operate with one bank of the larger safety-related backup heaters inservice. This affects the analyzed design basis in two ways. First, it delays the response of the other backup heater groups to restore pressure, which can result in exceeding the Technical Specification 3.4.1, Departure from Nucleate Boiling Limit, for short periods of time. This condition actually occurred for 2 minutes on August 12, 2005.

The second effect can cause the pressurizer power operated relief valve to lift early to arrest pressure.

The inspectors reviewed corrective actions from the 2005 event as well as procedures designed to adjust pressurizer bypass spray in a manner to allow for full power operation with only the backup heaters energized. When Wolf Creek attempted to complete this evolution in Mode 3 they were unable to maintain pressure throughout the entire range of spray bypass flow. As a result, Wolf Creek performed a system functionality assessment to continue operation with one bank of backup heaters energized. The functionality assessment was inspected as a separate item under Section 1R15. The inspectors reviewed corrective actions associated with the inability to meet the design basis for pressurizer pressure control and determined that Wolf Creek is taking reasonable corrective actions to resolve this deficiency. Wolf Creek intends to either modify the variable heaters sizing to permit power operation with backup heaters in automatic, or to reanalyze their design basis safety analyses to account for having one

bank of backup heaters normally energized. These corrective actions are due to be completed before restarting from the fall 2012 refueling outage.

These activities constitute completion of one in-depth problem identification and resolution sample as defined in Inspection Procedure 71152-05.

c. Findings

No findings were identified.

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

.1 (Closed) VIO 05000482/2011003-07, Failure to Correct Procedure for Opening Main

Steam Isolation Valves (EA-11-149).

The violation involved the failure to perform an adequate procedure change to preclude recurrence of safety system actuations when opening main steam isolation valves.

Although determined to be of very low safety significance (Green), this violation was cited in VIO 05000482/2011003-07 because not all of the criteria specified in Section 2.3.2 of the NRC Enforcement Policy were satisfied (EA-11-149). Specifically, Wolf Creek failed to restore compliance within a reasonable time for a previously NRC identified noncited violation as documented in NRC Integrated Inspection Report 05000482/2010004-01. The inspectors reviewed the corrective actions in root cause Condition Report 34964 and operating procedure revisions completed by the licensee. The inspectors verified that the cause was identified and that corrective actions were appropriate to prevent recurrence. This violation is closed.

These activities constitute completion of one sample in accordance with Inspection Procedure 71153-05.

.2 (Closed) Notice of Enforcement Discretion (NOED) 11-4-001, NOED for Wolf Creek

Nuclear Operating Corporation Turbine-Driven Auxiliary Feedwater Pump on August 14, 2011

a. Inspection Scope

On August 11, 2011, the turbine side of the turbine-driven auxiliary feedwater pump oil analysis had high particulates greater than the alert level. At 11:45 a.m., Wolf Creek entered Technical Specification 3.7.5, action statements C.1 and C.2. These action statements would require that the pump be made operable with 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or that the unit be placed in Mode 3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Over the next 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, Wolf Creek attempted several oil changes for the turbine and cleaned readily accessible portions of the turbine bearing housings in an effort to reduce the oil particulate count. After oil testing results continued to show elevated particulates while nearing the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limit, Wolf Creek requested enforcement discretion. Wolf Creek received enforcement discretion on August 14, 2011, for a period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. On August 15, at 11:45 a.m.,

the enforcement discretion expired and Wolf Creek had already started reducing reactor

power. The inspectors observed the power reduction from the control room. At 12:03 p.m., an engineering evaluation was completed for the remaining oil particulates and the pump was declared operable. The oil system had been sufficiently cleaned and oil exchanged several times to demonstrate operability. Wolf Creek was at 87 percent power when the pump was declared operable. The inspectors reviewed the compensatory actions described in the Notice of Enforcement Discretion. The inspectors walked down all safety systems requiring protected equipment signs and validated key equipment positions. The inspectors reviewed the offsite power surveillances and the Sharpe station availability rounds. The inspectors reviewed refueling practices for the Sharpe diesel station.

The NRCs written Notice of Enforcement Discretion can be found at ADAMS accession number ML112301699.

Documents reviewed by the inspectors are listed in the attachment.

These activities constitute completion of one sample in accordance with Inspection Procedure 71153-05.

b. Findings

(1) Verification of Implementation of Compensatory Measures and Commitments During walkdowns, the inspectors and the licensee found some protected equipment train signs missing from spaces that housed systems listed by the licensee during the verbal enforcement discretion discussion. These systems included essential service water, component cooling water, residual heat removal, vital air conditioning units, batteries, and the diesel-driven fire pump. The inspectors found protected train signs missing from one auxiliary feedwater valve compartment, essential service water piping (and valve) room, safety injection pump room B, residual heat removal pump rooms A and B, the boron injection tank room, residual heat removal heat exchanger rooms, and the electrical penetration rooms. The licensee restored the protected train signs and captured this issue in Condition Report 44402. No other work was in progress at this time.

(2) Turbine-driven Auxiliary Feedwater Pump Operability with Excessive Oil Particulates

Introduction.

The inspectors opened an unresolved item pending review of sufficient information concerning the effect the excessive oil particulate on the operability of the turbine-driven auxiliary feedwater pump.

Description.

Wolf Creek uses international standards organization, the solid contamination code, to measure the number and size distribution of oil particulates.

Each number describes a particle size distribution and the particle count scale is logarithmic. Wolf Creek Procedure I-ENG-004, Lubricating Oil Analysis, Revision 3A, has an alert limit of greater than 18/15 and an action limit of 19/16. On August 11, 2011, the oil analysis results were 23/21. On August 15, after several oil exchanges and use

of an in-line filtration skid, the oil was returned to the alert level of greater than 18/15.

Subsequent oil analysis of the as-found oil by an independent laboratory confirmed the elevated particulates and elevated water concentration. Analytical ferrography found that the particles consisted of ferrous debris from normal rubbing, fatigue, spherical wear, and oxidation. Wolf Creek has since contracted with a vendor to determine the operability impact on the turbine and governor. The inspectors will review that analysis to close this item. Therefore, this issue is unresolved pending more inspection of the vendor analysis of the turbine: URI 05000482/2011004-04, Excessive Oil Contamination for Turbine-Driven Auxiliary Feedwater Pump.

.3 (Closed) License Event Report (LER) 2011-006-00, Auxiliary Feedwater Actuation due to

Operators Inability to Control Steam Generator Level in Mode 4.

a. Inspection Scope

On May 24, 2011, Wolf Creek received a Lo Lo steam generator level due to a pressure increase and a corresponding shrink in level. The inspector responded to the control room, reviewed plant procedures, interviewed personnel, and reviewed plant computer trend data. The inspectors also reviewed LER 2011-006-00 for this event and the event notification under 10 CFR 50.72. This LER is closed.

These activities constitute completion of one sample in accordance with Inspection Procedure 71153-05.

b. Findings

Introduction.

On May 24, 2011, the inspectors reviewed a Green noncited violation of Technical Specification 5.4.1.a, Procedures, for the licensees failure to follow procedures for maintaining steam generator level above the Lo Lo setpoint.

Description.

On May 24, 2011, Wolf Creek was in Mode 5 and enabled the solid state protection system just after midnight. Steam generator levels were kept at 30 percent for steam generators B and C and 35 percent for steam generators A and D. This was in anticipation of performing Procedure STS AL-210, an auxiliary feedwater full-flow test, which would fill steam generators B and C. Mode 4 was achieved at 5:00 a.m. Steam generators were steaming to remove decay heat and levels. The operators placed the atmospheric relief valves in automatic to maintain reactor coolant system temperature after the reactor coolant system was heated and stabilized at 325 degrees Fahrenheit.

This caused a series of level shrinks and swells as the valves opened and closed to control steam pressure due to expanding and collapsing the steam bubbles in the steam generators. One shrink was as low as 24 percent level. The operators were also attempting to place steam generator blowdown in service, and swapped from auxiliary feedwater B to the motor-driven main feed pump. At 10:52 a.m., main control board annunciator 109A, S/G B HI/LO, and was lit for the following 28 minutes. At 11:20 a.m., a Lo Lo steam generator level (23.5 percent) was received on steam generator B which caused a reactor trip signal (the reactor was already subcritical), a feedwater isolation, and auxiliary feedwater actuation. Main feedwater was re-established at 1:41 p.m. on May 24.

The inspectors reviewed GEN 00-002 and found step 6.20.9 gave a steam generator level band of 40 to 60 percent or as directed by the control room supervisor.

Procedure STS AL-210, step 7.8, gave a level band of 40 to 60 percent.

Procedure GEN 00-002, step 6.19.3, stated to open the atmospheric relief valves as needed to control reactor coolant system temperature and maintain a heatup rate less than 100 degrees F/hr. After the event, the operators stated that the steam generator levels were maintained low to preclude a steam generator Hi Hi level signal at 74 percent during the auxiliary feedwater pump test. With low feedwater temperatures, steam generator levels would be challenging since under or over feeding would also causes shrink and swell in the generator. The inspectors and Wolf Creeks root cause found that the atmospheric relief valve controllers should have been left in manual to maintain a static valve position, steam pressure, and reactor coolant system temperature. The operators allowing the steam generators to shrink and swell for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> prior to the Lo Lo level was not appropriate to the circumstances and too much consideration was given to the Hi Hi level signal. The operators were overly concerned with allowing enough time to perform the auxiliary feedwater pump tests instead of controlling plant parameters.

Analysis.

The failure to maintain steam generator level above the engineered safety features setpoint is a performance deficiency. The finding was considered more than minor because it impacted the Initiating Events Cornerstone and its objective to limit the events that upset plant stability and challenge safety systems during power and shutdown operations. Specifically, this impacted the human performance attribute.

Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined the finding to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the loss of mitigation equipment. The reactor was shut down at the time. The inspectors determined that the finding has a crosscutting aspect in the area of human performance. Specifically, the decision by the crew to maintain steam generator level in a difficult to maintain band proved to have unintended consequences H.1.b].

Enforcement.

Wolf Creek Technical Specification 5.4.1.a, Procedures, requires, in part, that written procedures shall be established, implemented and maintained for the activities recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. The NRC Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, General Plant Operating Procedures, Section 2.j, requires procedures for cold shutdown to hot standby. Procedures GEN 00-002, Cold Shutdown to Hot Standby, Revision 76, implements this requirement. Step 6.20.9 stated to maintain a steam generator level of 40 to 60 percent or as directed by the control room supervisor.

The control room supervisor directed a level band between 30 and 40 percent. Contrary to the above, on May 24, 2011, Wolf Creek operators failed to maintain a level greater than 30 percent and caused a Lo Lo level signal below 23.5 percent. Because the finding is of very low safety significance and has been entered into the licensees corrective action program as Condition Report 39732, this violation is being treated as a noncited violation consistent with Section 2.3.2 of the NRC Enforcement Policy:

NCV 05000482/2011004-05, Failure to Maintain Steam Generator Level Above Lo Lo Level Setpoint.

.4 (Closed) VIO 05000482/2009005-01, Failure to Correct Discolored Boric Acid Deposits

The violation involved the failure to correct a condition adverse to quality regarding boric acid leakage accumulating on the refueling water storage tank. Although determined to be of very low safety significance (Green), this violation was cited in VIO 05000482/2009005-01 because not all of the criteria specified in Section 2.3.2 of the NRC Enforcement Policy were satisfied (EA-10-160). Specifically, Wolf Creek failed to restore compliance within a reasonable time for a previously NRC identified noncited violation as documented in NRC Integrated Inspection Report 05000482/2007006-03.

The inspectors reviewed the corrective actions completed by the licensee and verified that the cause was identified and that corrective actions were appropriate. During Refuel Outage 18 in the spring of 2011, Wolf Creek entered the tank and performed internal nondestructive examinations (dye penetrant and vacuum box testing) of welds the inside of the tank to identify the source of leakage. During these investigations, Wolf Creek identified three nonthrough-wall indications and four through-wall indications.

Two through-wall flaws were readily identifiable with the unaided eye. On May 20, 2011, Wolf Creek identified these findings to be a violation of 10 CFR 50.55a, this licensee identified violation is documented in Section 4OA7 of this report. This violation is closed.

These activities constitute completion of one sample in accordance with Inspection Procedure 71153-05.

.5 (Closed) LER 05000482/2008-005-00, Unanalyzed Condition Discovered due to

Improperly Installed Fuse in Class 1E Electrical Equipment Room Cooler On April 26, 2008, the licensee identified an improperly installed fuse in the train B, Class 1E electrical equipment room cooler. Specifically, the licensee identified that the redundant fuse used to ensure the room cooler could be started after a control room fire was installed in series with the control power transformer secondary side fuse, not in parallel as per design. In this condition, an electrical short on the control room side of the circuit could prevent the room cooler from being restarted.

The licensee determined that the wiring error occurred when the room cooler was replaced in the fall of 2003. Corrective actions included correcting the wiring error, inspecting other safe shutdown equipment with redundant fuses, and modifying the postmaintenance test procedure to ensure equipment with redundant fuses are properly wired.

This licensee-identified finding involved a violation of License Condition 2.C(5), Fire Protection. The enforcement aspects of the violation are discussed in Section 4OA7.

No additional issues were identified during this review. This licensee event report is closed.

This licensee event report review and event response under Section 4OA3.3 were considered as one sample under Inspection Procedure 71153-05.

.6 (Closed) URI 05000482/2009007-04, 345 kV Offsite Power System Compliance with

General Design Criterion 17 The sequence of events is detailed in NRC Integrated Inspection Report 05000482/2009-007 (ADAMS accession number ML100330574).

The inspectors reviewed Wolf Creeks original licensing basis from construction and found that two offsite power sources consisted of separate 69 kV and 345 kV switchyards. The inspectors reviewed NUREG 0882, Safety Evaluation Report Related to the Operation of Wolf Creek Generating Station, Unit No. 1, April 1982. The NRC reviewed and approved separate 345 kV and 69 kV switchyards as independent offsite power sources. On November 3, 1983, Wolf Creek submitted revised USAR site addendum pages that demonstrated compliance to offsite power system design and operating criteria with three 345 kV transmission lines. On August 16, 1985, the NRC issued a letter (Attachment VIII) on proposed modifications to several systems including offsite power. The cover letter also stated that the NRC approved of removal of one of the 345 kV lines and routing all offsite power through the 345 kV ring bus. The cover letter also stated: In addition, we have also enclosed a copy of the staffs safety evaluation related to the removal of one 345 kV offsite transmission line between Wolf Creek and West Gardner switching station. This evaluation which was docketed by staff memorandum dated March 14, 1984, is provided for your information. The inspectors reviewed the current revision of the Wolf Creek, USAR, Section 8.2.1.3, Offsite Power System Compliance with Design Criteria and Standards. This section states, in part,

that Benton, LaCygne, and Rosehill 345 kV lines are capable of carrying accidents loads and physically independent to the east and west 345 kV buses and then on to the 4 kV safety buses. It also states that the 345 kV ring bus meets General Design Criterion 17.

USAR, Section 8.2.1.3.g.1, states that, Any transmission line can be cleared under normal or fault conditions without affecting any other transmission line. USAR, Section 8.2.1.a states: There are three 345 kV lines connecting the Wolf Creek 345 kV substation to the area transmission system. The inspectors concluded that the 345 kV ring bus with three lines was Wolf Creeks design basis for offsite power. The inspectors found that the NRC approved three incoming 345 kV lines to a common ring bus as the sources of offsite power. A switchyard common to both trains is acceptable per General Design Criterion 17. See Section 1R04 for enforcement action for the August 19, 2009, loss of offsite power. This unresolved item is closed.

.7 (Closed) LER 2010-009-00, Pressurizer Level Higher than Allowed in Inadvertent

Operation of Emergency Core Cooling System Analysis The inspectors reviewed LER 2010-009-00. The inspectors reviewed the accompanying safety analysis in USAR, Section 15.5.1, Inadvertent Operation of the Emergency Core Cooling System While At Power. If safety injection was started during periods of higher level, there could have been significantly less time for operators to terminate the event and overfilling of the pressurizer. Based on inspector questioning and actual simulator runs with all the operating crews, the pressurizer may have been overfilled. The operating procedures permitting pressurizer level greater than the initial conditions of safety analysis have been changed to prevent overfilling of the pressurizer. Section 4OA7.3 documents a licensee-identified violation associated with this LER. This LER is closed.

These activities constitute completion of one sample in accordance with Inspection Procedure 71153-05.

.8 (Closed) LER 2011-007-00, Manual Reactor Trip due to Failed Controller Cards in the B

Feedwater Pump Turbine Control System

.a Inspection Scope On June 26, 2011, the resident inspectors responded to the control room when Wolf Creek was manually tripped from 82 percent power. The inspectors reviewed control room logs, plant computer data, and interviewed senior reactor operators regarding plant performance. The inspectors reviewed plant operating practices regarding methods of feedwater heating during low power operation. The inspectors attended plant safety review committee meetings and reviewed the findings of the root cause evaluation and other corrective actions.

These activities constitute completion of one sample in accordance with Inspection Procedure 71153-05.

.b Findings and Observations On June 26, 2011, at 4:09 p.m., CDT, the reactor was manually tripped due to the trip of the main feed pump B while operating at 82 percent power during restart and power ascension following Refueling Outage 18. The plant was stabilized in Mode 3 and Wolf Creek began troubleshooting the feed pump and initiated Condition Report 40895. The reactor was restarted on June 29 with one feed pump 59 percent power limitation.

When operators started the main feed pump B on June 30, it tripped unexpectedly after less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> in service. Operators were able to recover from the transient with the power limitations in place. Troubleshooting continued and it was determined that the cause was an intermittent hardware failure on the No. 4 or 5 position card on the MDT-20 main feedwater pump speed control cabinet. Both cards were replaced and the pump was successfully run on July 7 and power ascension to 100 percent was approved on July 8. The hardware failure analysis later determined that the failed component was the flow-to-voltage converter on the No. 4 position card. Wolf Creek performed a root-cause analysis as part of Condition Report 40895 and determined that the event was caused by delaying the replacement of the obsolete MDT-20 system. Wolf Creek made the decision to replace the system in 2003. The replacement was originally scheduled for Refueling Outage 17 (fall 2009) but was later deferred to Refueling Outage 19 (fall 2012). The inspectors reviewed records pertaining to this decision making process and concluded that Wolf Creeks root cause analysis was valid. No violation of regulatory requirements was identified. This LER is closed.

.9 (Closed) LER 2010-010-01, Inadequate Analysis Results in a Component Cooling Water

Train to be Declared Inoperable On September 22, 2010, while operating at 100 percent power during a component design basis inspection, the inspectors questioned Wolf Creek on the analysis of a postulated pipe break in the nonseismic portion of component cooling water system.

The component cooling water system consists of two trains with 100 percent capacity pumps per train. Each train supplies cooling water to independent safety loads and nonsafety loads (common service loop.) The postulated break was in the nonseismic portion of the common service loop that feeds radwaste. The radwaste section of piping is automatically isolated upon receipt of a safety injection signal, high flow indication in the nonsafety-related component cooling water piping, or a low component cooling water surge tank level.

After analyzing this postulated break, Wolf Creek determined that the original calculation had several nonconservative assumptions. The result was that the component cooling water surge tanks may not keep up with the break flow rate and could jeopardize the required component cooling water pump net positive suction head that would challenge pump operability. Wolf Creek declared the component cooling water train supplying cooling water to radwaste inoperable and entered the appropriate technical specification until radwater was isolated from the component cooling water system.

Since initial plant startup, radwaste has been aligned to one of the component cooling water trains and during short periods of time both component cooling water trains when shifting the radwaste alignment from one component cooling water train to the other

train. Because of this at least one component cooling water train was inoperable greater than its allowed technical specification outage time. Additionally, at times both component cooling water trains were considered inoperable depending on the status of the component cooling water trains, the alignment of radwaste operations being conducted. This violation was documented in an NRC Inspection Report as NCV 05000482/2010007-01, Inadequate Design of Component Cooling Water Safety/Nonsafety Isolation.

Upon review of LER 2010-010-01, the inspectors determined that corrective actions taken in response to NCV 05000482/2010007-01 are sufficient and no further actions are needed at this time. LER 2010-010-01 is closed.

These activities constitute completion of one sample in accordance with Inspection Procedure 71153-05.

4OA6 Meetings

Exit Meeting Summary

On August 25, 2011, the inspectors presented the results of the radiation safety inspection to Ms. A. Stull, Vice President, Chief Administrative Officer, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On September 14, 2011, the inspectors presented the results of the licensee event report closeout inspection to Mr. R. Zyduck, Manager, Design Engineering, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On October 5 and November 10, 2011, the resident inspectors discussed the inspection results with Mr. S. Hedges, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors acknowledged review of proprietary material during the inspection which was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy for being dispositioned as noncited violations.

.1 The licensee reported in LER 2008-005-00 that the train B, Class 1E electrical

equipment room cooler was miswired during replacement such that it might not be operable following a control room fire. This represented a violation of License Condition 2.C.(5), Fire Protection. A bounding Phase 3 evaluation concluded that this issue had very low safety significance (Green) since only 4 of the 103 control room cabinets could lead to a loss of the train B, Class 1E electrical equipment room cooler.

This issue was entered into the licensees corrective action program as performance improvement request 2008-001896.

.2 On June 1, 2011, Wolf Creek identified voiding in component cooling water train A when

a system engineer was reviewing plant computer data. Testing revealed voiding in both trains of component cooling water and Wolf Creek entered Technical Specification 3.0.3.

All the voids were vented. Subsequent engineering evaluation found that both trains were always operable. Wolf Creek root cause found that significant voids were trapped between valves EG HV-15 and EG HV-131, as well as between valves EG HV-16 and EG HV-131 following maintenance and fill and vent Procedure SYS EG-400. These portions of the piping were not recognized as trapping air and were not able to be vented. The inspectors used Inspection Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," a significance determination screening was performed and screened the issue to very low safety significance (Green) because there was no loss of operability or functionality. Technical Specification 5.4.1, Procedures, requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Regulatory Guide 1.33, Appendix A, Section 3.e, requires, in part, that instructions for filling and venting the component cooling water system should be covered by written procedures. Contrary to the above, from April 30 to June 1, 2011, the licensee failed to provide adequate instructions for filling and venting the component cooling water system. Specifically, station procedures allowed for gas accumulations in the component cooling water system, which affected the proper operation of the pumps during startup. This issue was documented in the licensees corrective action program as Condition Reports 25918 and 33925.

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

measures shall be established to assure that applicable regulatory requirements and the design basis, are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, on July 21, 2010, Wolf Creek did not translate the inadvertent safety injection safety analysis into procedures. Specifically, pressurizer level exceeded the initial conditions of plant safety analysis. This issue was identified by a Wolf Creek operations engineer and procedure writer. Wolf Creek USAR, Section 15.5.1, and safety analysis calculation AN-98-86 state that the initial condition of inadvertent operation of the emergency core cooling system is 57 percent pressurizer level. Operator action is necessary within 8 minutes to shut the boron injection tank valves. This prevents passing water through the pressurizer safety relief valves and escalating the event to a small break loss of coolant accident. Contrary to the above, from January 9, 2002, to January 25, 2011, Procedure GEN 00-005, Minimum Load to Hot Standby, Revisions 44 to 66, allowed pressurizer level up to 65 percent. Also, from December 14, 1994, to August 24, 2010, Procedure GEN 00-006, Hot Standby to Cold Shutdown, Revisions 28 to 73, allowed pressurizer levels up to 65 percent. This issue was determined to be of very low safety significance (Green) using a Phase 3 analysis because the maximum time the high water level condition existed was only nineteen hours.

.4 Title 10 CFR 50.55a, Codes and Standards, requires, in part, that the Wolf Creek

refueling water storage tank meet the requirements of the 1974 editions of the ASME Boiler and Pressure Vessel Code,Section III. Subsection NC-4424, Surfaces of Welds, requires, in part, that as-welded surfaces be sufficiently free from coarse ripples, grooves, overlaps, abrupt ridges and valleys so that the surface conditions of the finished weld shall be suitable for the proper interpretation of nondestructive examination of the welds. Subsection NC-5351, Evaluation of Indications, requires, in part, that any indication which is believed to be nonrelevant be regarded as a defect and be re-examined to verify whether or not actual defects are present. Contrary to the above, from September 3, 1985, to May 20, 2011, the Wolf Creek refueling water storage tank failed to meet the requirements of Subsection NC-4424 and NC-5351 due to four through-wall flaws that were identified. Wolf Creek repaired the affected welds prior to restarting the reactor. This issue is captured in Condition Reports 36857, 36880, 36881, 36937, and 36938. This issue was determined to be of very low safety significance (Green) because the functionality of the refueling water storage tank was not affected.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Beckett, Superintendent, Support Engineering

P. Bedgood, Manager, Radiation Protection

M. Bove, Senior Valve Engineer

R. Evenson, Requalification Program Supervisor

J. Harris, System Engineer

S. Hedges, Site Vice President

S. Henry, Operations Manager

R. Hobby, Licensing Engineer

D. Hooper, Supervisor, Regulatory Affairs

T. Just, Senior Technician, Chemistry

J. Keim, Support Engineering Supervisor

S. Koenig, Manager, Corrective Actions

M. McMullen, Technician, Engineering

C. Medency, Supervisor, Radiation Protection

W. Muilenburg, Licensing Engineer

R. Murray, Simulator Supervisor

B. Norton, Manage, Integrated Plant Scheduling

J. Pankaskie, Engineering Supervisor

G. Pendergrass, Director of Engineering

L. Rockers, Licensing Engineer

G. Sen, Regulatory Affairs Manager

R. Smith, Plant Manager

L. Solorio, Senior Engineer

M. Sunseri, President and Chief Executive Officer

J. Truelove, Supervisor, Chemistry

J. Weeks, System Engineer

M. Westman, Training Manager

NRC Personnel

C. Long, Senior Resident Inspector

C. Peabody, Resident Inspector

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000428/2011004-04 URI Excessive Oil Contamination for Turbine-Driven Auxiliary Feedwater Pump (Section 4OA3.2.b(2))

Opened and Closed

05000482/2011004-01 FIN Switchyard Component Failures Cause Loss of Ring Bus and Loss of Offsite Power Pump (Section 1R04)

05000482/2011004-02 NCV Technical Support Center External Door Propped Open without Impairment (Section 1R05)

05000482/2011004-03 NCV Failure to Follow ASME Code Case OMN-1 for Butterfly Valves (Section 1R22)

05000482/2011004-05 NCV Failure to Maintain Steam Generator Level Above Lo Lo Level Setpoint (Section 4OA3)

Closed

05000482/2011003-07 VIO Failure to Correct Procedure for Opening Main Steam Isolation Valves (EA-11-149) (Section 4OA3.1)

05000482/11-4-001 NOED Notice of Enforcement Discretion (NOED) 11-4-001, NOED for Wolf Creek Nuclear Operating Corporation, Turbine-Driven Auxiliary Feedwater Pump on August 14, 2011 (Section 4OA3.2)

05000482/2011-006-00 LER Auxiliary Feedwater Actuation due to Operators Inability to Control Steam Generator Level in Mode 4 (Section 4OA3.3)

05000482/2009005-01 VIO Failure to Correct Discolored Boric Acid Deposits (Section 4OA3.4)

05000482/2008-005-00 LER Unanalyzed Condition Discovered Due to Improperly Installed Fuse in Class 1E Electrical Equipment Room Cooler (Section 4OA.5)

05000482/2009007-04 URI 345 kV Offsite Power System Compliance with General Design Criterion 17 (Section 4OA3.6)

05000482/2010-009-00 LER Pressurizer Level Higher than Allowed in Inadvertent Operation of ECCS Analysis (Section 4OA3.7)

05000482/2011-007-00 LER Manual Reactor Trip due to Failed Controller Cards in the B Feedwater Pump Turbine Control System (Section 4OA3.8)

05000482/2010-010-01 LER Inadequate Analysis Results in a Component Cooling Water Train to be Declared Inoperable (Section 4OA3.9)

Attachment