IR 05000482/2009005

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

ML100430713
Person / Time
Site:	Wolf Creek
Issue date:	02/11/2010
From:	Geoffrey Miller NRC/RGN-IV/DRP/RPB-B
To:
References
ea-10-004, EA-10-020
Preceding documents:	ML100760439 (17 March 2010)
Download: ML100430713 (118)

Text

February 11, 2010 EA-10-004 EA-10-020 Matthew W. Sunseri, President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation P.O. Box 411 Burlington, KS 66839

SUBJECT: WOLF CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000482/2009005 AND NOTICE OF VIOLATIONS

Dear Mr. Sunseri:

On December 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Wolf Creek Generating Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 14, 2010, with you and other members of your staff. The inspections examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, the NRC has identified two issues that were evaluated under the risk significance determination process as having very low safety significance (green). The NRC has also determined that violations are associated with these issues. One violation involved failure to implement corrective actions to address refueling water storage tank leakage (EA-10-004). The second violation involved failure to correct an inadequate reactor vessel head vent path (EA-10-020). These violations were evaluated in accordance with the NRC Enforcement Policy included on the NRC's Web site at www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. The violations are being cited in the enclosed Notice of Violations (Notice) and the circumstances surrounding them are described in detail in the subject inspection report. The violations are being cited in the Notice because Wolf Creek Generating Station failed to restore compliance within a reasonable time after the violations were identified in NRC Inspection Reports05000482/2007003-006 and 05000482/2008004-007, as specified in Section VI.A.1 of the NRC Enforcement Policy.

You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response. The NRC will use your response, in part, to UNITED STATESNUCLEAR REGULATORY COMMISSIONREGION IV612 EAST LAMAR BLVD, SUITE 400ARLINGTON, TEXAS 76011-4125 Wolf Creek Nuclear Operating Corporation - 2 -

- 2 - determine whether further enforcement action is necessary to ensure compliance with regulatory requirements. Based on the results of this inspection, the NRC has also determined that one additional Severity Level IV violation of NRC requirements occurred. This report also documents 12 NRC identified and one self-revealing finding of very low safety significance (Green). All of these findings were determined to involve violations of NRC requirements. Additionally, two licensee-identified violations, which were determined to be of very low safety significance, are listed in this report. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as noncited violations, consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the violations or the significance of the noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Wolf Creek Generating Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, and its enclosure, will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/ Geoffrey B. Miller, Chief Project Branch B Division of Reactor Projects Docket No. 50-482 License No. NPF-42 Enclosure Inspection Report 05000482/2009005

w/Attachment:

Supplemental Information

Wolf Creek Nuclear Operating Corporation - 3 -

- 3 -

REGION IV Docket: 05000482 License: NPF-42 Report: 05000482/2009005 Licensee: Wolf Creek Operating Corporation Facility: Wolf Creek Generating Station Location: 1550 Oxen Lane SE Burlington, Kansas Dates: October 1 through December 31, 2009 Inspectors: C. M. Long, Senior Resident Inspector R. A. Kopriva, Senior Reactor Inspector J. F. Drake, Senior Reactor Inspector D. Loveless, Senior Reactor Analyst C. A. Peabody, Resident Inspector S. M. Alferink, Reactor Inspector P. A. Jayroe, Project Engineer C. Cauffman, Operations Engineer A. L. Fairbanks, Reactor Inspector C. C. Alldredge, Project Engineer G. M. Vasquez, Senior Health Physicist D. C. Graves, Health Physicist Approved By: G. B. Miller, Chief, Project Branch B Division of Reactor Projects

- 2 - Enclosure 2

SUMMARY OF FINDINGS

IR 05000482/2008005, 10/01/2009 - 12/31/2009; Wolf Creek Generating Station, Integrated Resident and Regional Report; Fire Protection, Inservice Inspection Activities; Maintenance Risk Assessments and Emergent Work Controls; Operability Evaluations; Plant Modifications; Refueling Outage and Other Outage Activities; Radiation Safety; Identification and Resolution of Problems, and Other Activities.

The report covered a 3-month period of inspection by resident inspectors and an announced baseline inspections by a regional based inspectors. Fourteen Green and one Severity Level IV noncited violation were identified and two Green cited violations were also identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination Process." Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," involving the licensee's failure to identify sources of boron leakage and document them in a corrective action document. Specifically, prior to October 23, 2009, the licensee failed to accomplish the requirements of Procedure AP 16F-001, "Boric Acid Corrosion Control Program," Revision 5, step 6.4.1, which states, in part, "Sources of boron seepage/leakage shall be identified/verified and documented in the applicable corrective action document." During a boric acid walkdown, the inspectors identified 11 sources of boron leakage which had not been previously identified and documented by the licensee. The licensee entered this finding into their corrective action system as Condition Report 00021274. The finding was determined to be more than minor because it was associated with the Initiating Events Cornerstone attribute of human performance and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors used Inspection Manual Chapter 0609, "Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings," and determined the finding was of very low safety significance (Green) because the issue would not result in exceeding the technical specification limit for identified reactor coolant system leakage or affect other mitigating systems resulting in a total loss of their safety function. The inspectors also determined that the finding had a crosscutting aspect in the area of problem identification and resolution, operating experience, where the licensee did not institutionalize operating experience through changes to station processes, procedures, equipment, and training programs [P.2.(b)] (Section 1R08.2.b).

Green.

On December 16, 2009, inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," involving failure to obtain vendor design data for a modification. In August 2009, a component cooling water modification was made to the reactor coolant pump thermal barrier heat exchangers' flow rates as a corrective action to VIO 05000482/2009002 07 (EA-09-110). A flow rate above the previous design value was justified by an internal memo of a vendor opinion from a telephone conversation in 1992. The inspectors found this to be contrary to Procedure AP 05-005, for obtaining data from vendors. The notice of violation will remain open until full compliance has been restored. Wolf Creek consulted with Westinghouse, confirmed the acceptability of the increased flow rate, and requested a formal calculation. This issue is captured in Condition Report 22824. The inspectors determined that this finding was more than minor because this issue aligned with Inspection Manual Chapter 0612, Appendix E, example 2.f, in that the modification relied on verbal statements to raise the allowable flow through the heat exchanger. This is a significant deficiency in the modification package. The inspectors determined this finding was associated with the design control attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609.04 and determined that the finding was of very low safety significance because assuming worst case degradation, the finding would not result in exceeding the technical specification limit for identified reactor coolant system leakage and would not have likely affected other mitigation systems resulting in a total loss of their safety function because seal injection was available. This finding has a crosscutting aspect in the area of human performance associated with work practices in that management was unsuccessful in communicating expectations on procedure use and adherence in engineering H.4.b] (Section 1R18).

Green.

The inspectors identified a cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," due to an inadequate vent path for the reactor vessel head. The inadequate vent path resulted in the formation of voids in the reactor vessel head during Refueling Outage 17. Failure to ensure an adequate vent path in the reactor vessel head was the subject of a noncited violation in NRC Inspection Report 05000482/2008004. During and after Refueling Outage 16, Wolf Creek initiated a root cause evaluation and corrective actions to prevent occurrence. When one of the possible root causes was disproven in Refueling Outage 17, no additional action was taken to determine the cause of the vessel head vent blockage. However, the licensee could not exclude blockage in the piping. This issue was entered into the corrective action program and the licensee plans to conduct a more thorough inspection of the piping during the next refueling outage. This issue is being tracked by the licensee as Condition Report 22501. The inspectors determined that the failure to provide adequate vessel head vent path to prevent gas accumulation in the reactor vessel during depressurized plant operations was a performance deficiency. The inspectors determined that this finding, which was associated with the Initiating Events Cornerstone, was more than minor because if left uncorrected, it would have become a more significant-safety concern. Specifically, without an adequate vent path the reactor vessel does not have an effective means of relieving noncondensable gases to prevent a loss of reactor coolant system inventory. The inspectors evaluated this finding using Inspection Manual Chapter 0609, Appendix G, Attachment 1, and determined it be of very low safety significance based upon the demonstrated availability of mitigating systems and the flooded reactor cavity inventory. The inspectors determined the cause of the finding had a problem identification and resolution aspect in the corrective action program. Specifically, Wolf Creek's corrective actions were not successful to address the vent path blockage in a timely manner P.1(d) (Section 1R20).

Green.

The inspectors identified a noncited violation of License Condition 2.C.(5), "Fire Protection," for the failure to implement and maintain the approved fire protection program. Specifically, the licensee prescribed mitigating actions in response to certain fire scenarios that would result in a loss of circuit breaker coordination and could initiate secondary fires in plant locations outside of the initial fire area. The licensee entered this issue into their corrective action program as Condition Report 2008-005210.

This finding was more than minor because it was associated with the Protection Against External Factors attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The risk significance of this finding was determined using Manual Chapter 0609, Appendix F,

"Fire Protection Significance Determination Process." The finding was determined to be of very low safety significance using a Phase 2 evaluation. This finding was not assigned a crosscutting aspect because the cause was not representative of current performance (Section 4OA5.2).

Cornerstone: Mitigating Systems

Green.

The inspectors identified a cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for failure to take action to stop leakage from the base of the refueling water storage tank or evaluate the leakage and wastage for acceptability. Specifically, the licensee did not take actions to prevent recurring discolored boric acid deposits for approximately 11 years. Failure to correct leakage from the refueling water storage tank base was the subject of a noncited violation in NRC Inspection Report 05000482/2007006. This issue was entered into the licensee's corrective action program as Condition Report 22866. The failure to implement corrective actions for the refueling water storage tank leakage was a performance deficiency. The inspectors determined this issue impacted the Mitigating Systems Cornerstone and was greater than minor because if left uncorrected, the failure to correct the presence of boric acid leakage could become a more significant safety concern in that continued wastage could impact tank operability. Using the Phase 1 worksheets in Inspection Manual Chapter 0609.04, "Significance Determination Process," the finding was determined to have very low safety significance because it did not result in a system or component being inoperable and it did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors identified a crosscutting aspect in the area of human performance associated with resources. Specifically, Wolf Creek did not maintain long-term plant safety minimizing corrective maintenance deferrals and this long-standing equipment issue H.2.c] (Section 1R05).

Green.

The inspectors identified a noncited violation of Technical Specification 5.4.1.a, for an inadequate Procedure AP-10-101, "Control of Transient Ignition Sources." On October 21, 2009, the inspectors observed maintenance personnel performing weld preparation work on essential service water piping to containment cooler B using a flapper wheel. The inspectors observed that the ignition control barriers for the hot work were insufficient in that the sparks from the preparation work extended four to five feet from the job site and there was no fire watch posted. On December 4, 2003, a procedure revision inappropriately incorporated a change to the procedure where a fire watch did not have to be posted when using "wire brushes, flapper wheels, polishing devices, or Rol-Lok type buffing pads mounted on power grinder motor drives or air tools." The maintenance supervisor stopped the work until a fire watch was posted. The licensee entered this into their corrective action system as Condition Report 20993.

This finding is more than minor because it affected the Mitigating Systems Cornerstone attribute of "Protection Against External Factors - Fires," and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The lack of a posted fire watch could adversely affect the ability to achieve and maintain safe shutdown in the event of a severe fire in the affected area. Inspection Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process," could not be used to effectively evaluate the finding and defense-in-depth strategies because the 2003 changes to the fire watch program affected multiple fire areas and conditions. Therefore, in accordance with Inspection Manual Chapter 0609, Appendix M, the safety significance was determined by regional management review who concluded that the finding was of very low safety significance (Green). This finding was reviewed for crosscutting aspects and none were identified. The original change occurred in 2003 and was not indicative of current performance (Section 1R05.2).

Green.

The inspectors identified a noncited violation of 10 CFR 50.65(a)(4) involving the failure to adequately perform shutdown risk assessments during Refueling Outage 17. Between October 10 and November 17, 2009, Wolf Creek did not appropriately consider electrical power, decay heat removal, and containment when assessing shutdown risk. This changed the outcome or color of the qualitative calculation on several occasions. The licensee entered this issue in their corrective action program as Condition Reports 22295 and 22296. The failure to meet shutdown risk assessment requirements in the daily shutdown risk assessment process is a performance deficiency. The inspectors determined this finding was associated with the Mitigating Systems Cornerstone and was more than minor because it involved incorrect risk assessment assumptions by omitting requirements specified in committed guidance without providing justification for that omission. Such errors of omission have the potential to change the outcome of the licensee's maintenance risk assessment as described above. Per Inspection Manual 2 Chapter 0609, Appendix K, "Maintenance Risk Assessment and Risk Management Significance Determination Process," licensees who only perform qualitative analyses of plant configuration risk due to maintenance activities, the significance of the deficiencies must be determined by an internal NRC management review using risk insights where possible in accordance with Inspection Manual Chapter 612, "Power Reactor Inspection Reports." The NRC management review concluded that this finding was of Green safety significance because missing risk management actions did not result in loss of key shutdown risk functions. Additionally, the cause of the finding has a human performance crosscutting aspect in the area associated with the resources. Specifically, Wolf Creek did not ensure that Procedure APF 22B-001-02 was complete, accurate, and up-to-date H.2(c) (Section 1R13).

Green.

On November 18, 2009, the inspectors identified a noncited violation of Technical Specification 3.0.4.b for ascension from Mode 4 to Mode 3 without establishing required risk management actions. Wolf Creek used technical specification Limiting Condition for Operation 3.0.4.b to permit mode ascension after performance of a risk assessment and identification of risk management actions to maintain safety in the next mode. The turbine-driven auxiliary feedwater pump was inoperable per Technical Specification 3.7.5. As a risk management action, protected train signs would be placed on the doors to the motor-driven auxiliary feedwater Pump A and B room doors. A walkdown conducted by the inspector on the morning of November 18, 2009, found that the protected train signs on the motor-driven auxiliary feedwater pump rooms were not in place. Also, a maintenance crew was performing radiography in the motor-driven auxiliary feedwater pump Room B. The motor-driven auxiliary feedwater Pumps A and B were also made inoperable (at separate times) later on the morning of November 18, 2009. The licensee entered this issue in their corrective action program as Condition Report 21926. Mode ascension under Technical Specification LCO 3.0.4.b without establishing required risk management actions is a performance deficiency. The finding was more than minor because it was associated with the configuration control and alignment attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The configuration control issues not only included the work being completed on the turbine-driven auxiliary feedwater pump, but also included containment isolation valve testing and radiography that was performed on the motor-driven auxiliary feedwater pumps which was not included in the risk assessment. The inspector used Inspection Manual Chapter 0609.04, to determine that the finding was of very-low safety significance (Green) because it did not result in a loss of system safety function; did not exceed allowable technical specification outage time; and was not a seismic, flooding, or severe weather concern. Additionally, the cause of the finding has a human performance crosscutting aspect in the area associated with decision making. Specifically, Wolf Creek used a risk assessment form and an informal mode change form to communicate between departments the requirement for risk management actions. The two forms were in conflict and the personnel who implemented the risk management actions were not informed H.1(c) (Section 1R13).

Green.

On October 15, 2009, the inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for failure to follow Procedure AP 28A-100, "Condition Reports." Wolf Creek failed to initiate a condition report for evaluation of corrosion on containment cooler A piping. After inspector challenging, Wolf Creek initiated condition reports, performed nondestructive testing, replaced corroded studs, and evaluated the cause of the corrosion. The inspectors determined that the failure to follow AP 28A-100, Appendix C, was a performance deficiency. This issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, the issue screened to Green because there was not a loss of operability and the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. A crosscutting aspect was identified in the problem identification and resolution area of the corrective action program. Specifically, Wolf Creek failed to implement a corrective action program with a low threshold for identifying issues P.1.a] (Section 1R13).

Green.

On November 23, 2009, a self-revealing violation of Technical Specification 5.4.1.a was identified when a technician failed to follow procedure and emptied 45 gallons of oil from centrifugal charging Pump A rendering the pump inoperable. The technician was supposed to remove the temperature indicator for calibration but instead removed the thermowell which breached the lube oil subsystem of centrifugal charging Pump A. An unplanned entry into Technical Specification 3.5.2, Condition A, was made for approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. The licensee entered this issue in their corrective action program as Condition Report 21993. The failure to follow station procedures and correctly remove the detector was a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609.04, and determined that the finding was of very low safety significance (Green) because the pump was inoperable for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Also, the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors identified a human performance crosscutting in the area of work practices because self-checking and communication with the supervisor failed to prevent the event H.4.a] (Section 1R13).

Green.

On November 5, 2009, inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure to perform an adequate operability evaluation required by procedure. The inspectors identified that Operability Evaluation EF 09-010, Revisions 0 and 1, did not demonstrate that the essential service water pumps could withstand a safe shutdown earthquake.

Revision 2 of the operability evaluation included calculations to demonstrate acceptable stresses and included pump impeller clearances. This issue is captured in the corrective action program as condition reports 22798 and 21572. The failure to perform an adequate operability evaluation per Procedures AP 28-001 and AP 26C 004 was a performance deficiency. The inspectors determined that this finding was more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and it affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, this issue relates to the availability and reliability examples of the equipment performance attribute because a latent common mode failure mechanism was not correctly evaluated. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609, Appendix A, and determined that the finding was of very low safety significance (Green) because the issue was not a design or qualification deficiency confirmed to result in loss of operability or functionality, did not represent a loss of system safety function, an actual loss of safety function of a single train for greater than its technical specification allowed outage time, an actual loss of safety function of a nontechnical specification risk-significant equipment train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The cause of the finding has a problem identification and resolution crosscutting aspect associated with the corrective action program because Wolf Creek failed to thoroughly evaluate the failure mechanism such that the resolutions address the causes and extent of conditions, as necessary P.1.c] (Section 1R15).

Green.

The inspectors identified a noncited violation of Technical Specification 5.4.1.a for failure to properly implement Procedure AP 14A-003, "Scaffold Construction and Use," when scaffolding was erected against operable safety-related equipment. On October 15, 2009, the inspectors walked down containment and identified scaffolding in contact with component cooling water piping. The tag on the scaffold explicitly stated that it was not seismically qualified. At the time, both steam generators were inoperable and both trains of residual heat removal were required to be operable. The inspectors reviewed the bases for Technical Specification 3.4.7, "RCS Loops - Mode 5, Loops Filled," which required an operable heat sink path from residual heat removal to component cooling water to essential service water. This issue was entered into the corrective action program as Condition Report 22464. The construction of an unqualified scaffold against operable component cooling water piping was a performance deficiency. The inspectors determined that this finding was more than minor because it is associated with the equipment performance attribute for the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, this issue relates to the availability and reliability examples of the equipment performance attribute because a latent failure mechanism was not evaluated. The inspectors evaluated the significance of this finding using Inspection Manual Chapter 0609, Appendix G, Attachment 1, "Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs." The inspectors determined that Checklist 3 was applicable because the unit was in cold shutdown with the refueling cavity level less than 2 23 feet. Using Appendix G, Attachment 1, Checklist 3, Phase 2 analysis was not needed and the finding was of very low safety significance (Green) because the licensee was able to demonstrate that the seismically unqualified scaffolding would not have resulted in a loss of safety function. The inspectors determined the cause of the finding had a human performance aspect in the area of resources. Specifically, Procedure AP 14A-003 was inadequate because it had conflicting guidance that allowed seismically unqualified scaffolds in Modes 5 and 6 H.2.c] (Section 1R20).

Cornerstone: Barrier Integrity

Green.

The inspectors identified a noncited violation of Technical Specification 3.3.1, Condition I, for making positive reactivity addition prohibited by technical specifications in Mode 2 because one source range nuclear instrument channel was inoperable. Following a reactor transient, one of the source range nuclear instrument channels experienced an unanticipated increased count rate and was declared inoperable. Wolf Creek restored the channel in an operability evaluation which cited the cause as a problem in a component which was later determined not to exist in the installed configuration; however, the improperly restored equipment had already been used for to support plant startup on August 22, 2009. Wolf Creek replaced the detector during Refueling Outage 17. This issue was entered into the correction action program as Condition Report 20208. Reactivity addition with source range channel Nuclear Instrument-31 inoperable is a performance deficiency. The finding was more than minor because it was associated with the configuration control (reactivity control) attribute of the Barrier Integrity Cornerstone, and it affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609.04, and determined that the finding screened to Green because the finding only affected the fuel barrier. Additionally, the cause of the finding has a human performance crosscutting aspect in the area associated with the decision making. Specifically, Wolf Creek did not use conservative assumptions in decision making and adopt requirements to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action, when performing an operability evaluation for the source range Nuclear Instrument 31 detector prior to restarting from a forced outage H.1(b) (Section 1R15).

Green.

On December 30, 2009, the inspectors identified a noncited violation of Technical Specification Table 3.3.1-1, Function 18.a, when Wolf Creek restarted on May 18, 2005. During a reactor shutdown on October 7, 2006, intermediate range neutron detector Nuclear Instrument-36 did not decrease below 6E -11 amps and energize source range detector Nuclear Instrument-32. The detector was not replaced until Refueling Outage 16 in March 2008. The licensee entered this issue in their corrective action program as Condition Report 22450 The inspectors determined that the failure to ensure that the P-6 interlock was operable per the technical specification as defined in the bases was a performance deficiency.

2 The finding was more than minor because it was associated with the configuration control (reactivity control) attribute of the Barrier Integrity Cornerstone, and it affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609.04, and determined that the finding screened to Green because the P-6 interlock only affected the fuel barrier (Section 4OA2). This finding was not assigned a crosscutting aspect because the cause was not representative of current performance.

Cornerstone: Occupational Radiation Safety

Green.

The inspector identified a noncited violation of Technical Specification 5.7.2.a.1 for failure to maintain administrative control of door and gate keys to high radiation areas with dose rates greater than 1 rem per hour but less than 500 rads per hour (referred to as locked high radiation areas). Specifically, as of October 21, 2009, the licensee did not have administrative controls over a single master key to locked high radiation areas.

This issue was entered into the licensee's corrective action program as Condition Report 20973. Failure to maintain administrative control of the master key to locked high radiation areas was a performance deficiency. This finding is greater than minor because if left uncorrected the finding has the potential to lead to a more significant safety concern in that an individual could receive unanticipated radiation dose by gaining access a locked high radiation area without the proper controls and briefing. This finding was evaluated using the occupational radiation safety significance determination process and determined to be of very low safety significance because it did not involve: (1) as low as is reasonably achievable planning or work control issue, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. Additionally, the violation has a crosscutting aspect in the area of human performance associated with the work practices component because the lack of peer and self-checking resulted in inadequate control of keys to locked high radiation areas H.4(a) (Section 2OS1).

Cornerstone: Miscellaneous

• Severity Level IV. The inspectors identified a Severity Level IV noncited violation of 10 CFR 50.73 in which the licensee failed to submit a licensee event report within 60 days following discovery of events or conditions meeting the reportability criteria. On December 31, 2009, the inspectors identified a licensee event report that was no timely. Licensee Event Report 2009-009-00 was not issued within 60 days for a condition prohibited by technical specifications, and the event report did not identify that the disabling of both trains of the P-4 interlock on August 22, 2009 was also reportable per 10 CFR 50.73(a)(2)(v). The P-4 interlock was required by Technical Specification 3.3.2, function 8.a, and is discussed in USAR, Section 7.3.8, "NSSS Engineered Safety Feature Actuation System." Wolf Creek licensee event report 2009-009 was correct in that the interlock is not credited in accident analysis. However, NUREG 1022, Section 3.2.6, specifies that inoperable systems required by the technical specifications be reported, even if there are other diverse operable means of accomplishing the safety function.

2 The inspectors reviewed this issue in accordance with Inspection Manual Chapter 0612 and the NRC Enforcement Manual. Through this review, the inspectors determined that traditional enforcement was applicable to this issue because the NRC's regulatory ability was affected. Specifically, the NRC relies on the licensee to identify and report conditions or events meeting the criteria specified in regulations in order to perform its regulatory function, and when this is not done, the regulatory function is impacted. The inspectors determined that this finding was not suitable for evaluation using the significance determination process, and as such, was evaluated in accordance with the NRC Enforcement Policy. The finding was reviewed by NRC management, and because the violation was determined to be of very low safety significance, was not repetitive or willful, and was entered into the corrective action program, this violation is being treated as a Severity Level IV noncited violation consistent with the NRC Enforcement Policy. This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program in that the licensee failed to appropriately and thoroughly evaluate for reportability aspects all factors and time frames associated with the inoperability of the engineered safety features actuation system P.1(c) (Section 4OA3).

B. Licensee-Identified Violations

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

2

REPORT DETAILS

Summary of Plant Status The plant started the inspection period at 100 percent rated thermal power. On October 10, 2009, Wolf Creek shutdown for Refueling Outage 17. On November 17, 2009, Wolf Creek achieved criticality and on November 24, 2009, Wolf Creek achieved 100 percent power and remained there for the remainder of the inspection period.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Readiness to Cope with External Flooding

a. Inspection Scope

On October 28, 2009, the inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood. The evaluation included a review to check for deviations from the descriptions provided in the Updated Safety Analysis Report (USAR) for features intended to mitigate the potential for flooding from external factors. As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable. Additionally, the inspectors performed a walkdown of the protected area to identify any modification to the site that would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier. The inspectors also reviewed the abnormal operating procedure for mitigating the design basis flood to ensure it could be implemented as written.

These activities constitute completion of one external flooding sample as defined in Inspection Procedure IP 71111.01-05.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

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

• October 21, 2009, Train A while emergency diesel generator B and offsite power out of service for maintenance

• October 21, 2009, Spent fuel pool train A while spent fuel pool train B out of service The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating Procedures, system diagrams, USAR, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of two partial system walkdown samples as defined in Inspection Procedure IP 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.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:

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

• October 29, 2009, Spent fuel pool Room A

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

• November 12, 2009, Refueling water storage tank valve house The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensee's fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's 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 plant's 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 licensee's corrective action program. Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of four quarterly fire-protection inspection samples as defined by Inspection Procedure IP 71111.05-05.

.1 Failure to Correct Discolored Boric Acid Deposits

Introduction.

The inspectors identified a Green cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure to take action to stop leakage from the base of the refueling water storage tank or evaluate the leakage and wastage for acceptability.

Description.

During the component design basis inspection in June 2007, the inspection team noted white and brown deposits resembling boric acid at the base of the refueling water storage tank. The licensee informed the team that past analysis had determined these deposits were from calcium-silicate insulation which had been used for insulating the refueling water storage tank. In 1998, the licensee had initiated Problem Identification Request 1998-3860 to pursue the nature of the deposits and discovered that the deposits did contain amounts of insulation, but also contained boron. The licensee had dismissed the boron as spillage from a sampling evolution. On two subsequent occasions after 1998, the deposits were questioned by the licensee and again dismissed as insulation based on the 1998 resolution. In each of these cases the deposits were cleaned up, and the problem identification requests written only addressed the poor materiel condition of the area. The component design basis inspection team questioned the previous conclusions that the deposits were insulation material based on the strong resemblance to boric acid deposits from leakage of reactor coolant from the refueling water storage tank. The licensee sent samples of the deposits for offsite laboratory analysis, which confirmed that the deposits contained boron. Subsequently, the licensee performed inspections of the carbon steel components in the area and determined that no significant wastage had occurred and operability of the refueling water storage tank and its surrounding components was not affected. The inspection team documented a noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, for inadequate corrective actions in response to the leakage from the refueling water storage tank, documented in NRC Inspection Report 05000482/2007006 (ADAMS ML072880678) On November 12, 2009, the resident inspectors walked down the refueling water storage tank valve house and again identified that the base of the refueling water storage tank had deposits that resembled boric acid in several locations. Some deposits had progressed up the tank bolting several inches from the floor. Initially, Wolf Creek again maintained that the deposits were calcium silicate from insulation. The inspectors questioned the licensee about the deposits, and laboratory testing again demonstrated the presence of boric acid. The inspectors reviewed the actions Wolf Creek had taken in response to NCV 05000482/2007006-03 in the component design basis inspection report. Wolf Creek had performed a boric acid corrosion evaluation as part of Work Order 07-300734-000, which concluded that the refueling water storage tank leak was not active, though the tank deposits reappeared after cleanings in July 2007, August 2008, March 2009, June 2009, and September 2009. Wolf Creek attempted to repair roof leaks in the refueling water storage tank valve house as a source of rain water ingress, but took no action to address the source of the boric acid in the deposits. Wolf Creek took several samples of deposits from the base of the refueling tank. Though one sample in June 2009 did not contain boric acid, the majority of samples, including the most recent sample from November 2009, did contain boron, indicating that leakage from the base of the refueling water storage tank continued to exist. The inspectors concluded that Wolf Creek had failed to restore compliance from the noncited violation involving the failure to correct refueling water storage tank leakage in the component design basis inspection report.

Analysis.

The failure to implement corrective actions for the refueling water storage tank leakage was a performance deficiency. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC's regulatory function, and the finding was not the result of any willful violation of NRC requirements or Wolf Creek procedures. The issue was greater than minor because if left uncorrected, the failure to correct the presence of boric acid for extended periods of time would become a more significant-safety concern, in that, continued wastage could impact the studs and tank operability. The finding affected the Mitigating Systems Cornerstone, using the Phase 1 worksheets in Inspection Manual Chapter 0609.04, "Significance Determination Process." The inspectors determined that the finding had very low safety significance (Green) because it did not result in a system or component being inoperable and it did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors identified a crosscutting aspect in the area of human performance associated with resources. Specifically, Wolf Creek did not maintain long-term plant safety minimizing corrective maintenance deferrals and this long-standing equipment issue H.2(c).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, from 1998 to December 31, 2009, Wolf Creek did not correct the condition adverse to quality. Specifically, Wolf Creek did not take action to correct leakage from the refueling water storage tank. This issue and the corrective actions are being tracked in Condition Reports 2007-02742 and 22866. Due to the licensee's failure to restore compliance from previous NCV 05000482/2007006-03 within a reasonable time after the violation was identified, this violation is being cited as a Notice of Violation consistent with Section VI.A of the Enforcement Policy: VIO 05000482/2009005-01, "Failure to Correct Discolored Boric Acid Deposits" (EA-10-004).

.2 Control of Transient Ignition Sources

Introduction.

The inspectors identified a noncited violation of Technical Specification 5.4.1.a for an inadequate procedure for control of transient ignition sources due to exempting the use of "flapper wheels" from the requirements of AP 10-101, "Control of Transient Ignition Sources."

Description.

On October 21, 2009, NRC inspectors observed maintenance personnel performing weld preparation work on essential service water piping to containment cooler B. The inspectors observed that the ignition control barriers for the hot work were insufficient, in that the sparks from the preparation work extended four to five feet from the job site and there was no fire watch apparent. When the inspectors questioned the maintenance personnel regarding the posting of a fire watch, the maintenance personnel stated that they were using a flapper wheel and a fire watch was not required.

On December 4, 2003, the licensee modified Procedure AP-10-101, "Control of Transient Ignition Sources," such that the use of flapper wheels was exempted from the requirements of Procedure AP10-101. The inspectors determined that the revised procedure adversely affected the fire safety in the affected area. This was based on recognition that the ability of the fire watch was not limited to fire identification in a timely manner, but also on mitigation actions that an established fire watch could take in the event of fires. These could include such actions as the ability to close doors limiting fire exposure to adjacent areas and providing more timely fire detection capability in certain cases. The inspectors concluded that the licensee inappropriately revised the procedure to exempt the use of all flapper wheels without posting a fire watch. The inspectors determined that the inadequate procedure increased the risk of fires in the plant.

Analysis.

The licensee's failure to provide an adequate procedure to control transient ignition sources was a performance deficiency and was reasonably within the ability of the licensee to prevent. The inspectors concluded that this issue had a realistic likelihood of affecting safety. Failure to properly evaluate the removal of the fire watch posting requirements could adversely affect or degrade the ability of the licensee to identify and report fires caused by hot work, in a timely manner. Specifically, the use of nonconservative exemptions for requiring fire watches to be posted could affect the ability to adequately reduce the risk of fires in the plant. This finding is more than minor because it affected the Mitigating Systems Cornerstone attribute of "Protection Against External Factors - Fires," and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The lack of a posted fire watch could adversely affect the ability to achieve and maintain safe shutdown in the event of a severe fire in the affected area. Inspection Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process," could not be used to effectively evaluate the finding in relation to defense-in-depth strategies because it had potential effects across multiple areas and conditions. Therefore, in accordance with Inspection Manual Chapter 0609, Appendix M, the safety significance was determined by regional management review and concluded that the finding was of very low safety significance (Green) since there were no combustibles in the immediate area and fire extinguishers were readily available. The capability of other principal defense-in-depth fire protection features were unaffected, such as the associated fire barriers, control of transient combustibles, manual fire suppression equipment, and the fire brigade. Additionally, the finding was not associated with a qualification deficiency, did not result in a loss of safety function for a system, and was not risk significance due to external initiating events.

Enforcement.

Technical Specification 5.4.1.a requires, in part, that written procedures shall be established and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1972. Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operation)," Revision 2, Appendix A, Section 1.l, requires that procedures be written for plant fire protection program. Contrary to this requirement, from December 4, 2003, until October 21, 2009, the licensee inappropriately exempted the use of flapper wheels from the requirements of Procedure AP 10-101, "Control of Transient Ignition Sources," reducing the fire safety of the plant. Because this issue was determined to be of very low safety significance (Green) and was entered into the licensee's corrective action program as Condition Report AR 00020993, this violation is being treated as a noncited violation in accordance with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2009005-02, "Control of Transient Ignition Sources."

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the USAR, the flooding analysis, and plant procedures to assess seasonal susceptibilities involving internal flooding; reviewed the USAR and corrective action program to determine if licensee personnel identified and corrected flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; verified that operator actions for coping with flooding can reasonably achieve the desired outcomes; and walked down the area listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers. Specific documents reviewed during this inspection are listed in the attachment.

• October 6, 2009, Auxiliary feedwater rooms and sump pumps These activities constitute completion of one flood protection measures inspection sample as defined by Inspection Procedure IP 71111.06-05.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

.1 Annual Inspection

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records.

• January 14, 2009, STN PE-38 on containment cooler SGN01D The inspectors verified that performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the periodic maintenance method outlined in Electric Power Research Institute Report NP 7552, "Heat Exchanger Performance Monitoring Guidelines;" the licensee properly utilized biofouling controls; the licensee's heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was correctly categorized under 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of one heat sink inspection sample as defined by Inspection Procedure IP 71111.07-05.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water Reactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control (71111.08-02.01)

a. Inspection Scope

The inspection procedure requires review of two or three types of nondestructive examination activities and, if performed, one to three welds on the reactor coolant system pressure boundary. It also requires review of one or two examinations with relevant indications (if any were found) that have been accepted by the licensee for continued service.

The inspectors directly observed the following nondestructive examinations: SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Feedwater System Check Valve. Root pass indication repair. Area 5, West Bay Drawing WIP-M-13AE05-012-A-1 WO 08-305300-049 MT Charging Pump Room B Vent valve. 1974 foot elevation auxiliary building, Room 1108 Drawing WIP-M-13BG02-006-A-1 WO 08-310289-043 PT Safety Injection Vent Valve. Located in safety injection pump Room A Drawing WIP-M-13EM01-008-A-1 WO 0-310289-077 PT Chemical and Volume Control System Blowdown line coupling letdown heat exchanger room Drawing M-13BG34 WO 06-288993-000 PT Feedwater System Check valve hinge pin seal weld. 2047 foot elevation, RB C loop Drawing WOP-M-13AE04-008-A-1 WO 08-305300-013 PT SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Feedwater System Check valve - flange to pipe weld joint. 2026 elevation of Area 5 WO 08-305300-048 and -049 RT Reactor Vessel Closure Head RPV meridonal welds, ISI Number CH-101-104-B UT Reactor Vessel Closure Head RPV meridonal weld, ISI Number CH-101-104-C UT High Pressure Safety Injection HPSI pipe to elbow weld, ISI Number EM-03-S015-B UT Residual Heat Removal Pipe to Pipe Weld, ISI Number EJ-04-F019 UT Reactor Vessel Closure Head Reactor vessel washer and Bushings 19-24, Component CH-WASH 19-24 Drawing M-189-50ISI-RBB01 WO 08-311169-014 VT - 1 Safety Injection Vent valve. Safety injection pump Room A Drawing WIP-M-13EM01-008-A-01 WO 08-310289-068 VT - 1 Reactor Vessel Head Required by 10FR50.55a, ASME Code Case N-729-1. Also IEWA-2212 VT-2 under mirror insulation WO 08-307175-001 VT - 2 Piping Support In containment Component EJ-04-H002 WO 08-311169-001 VT- 3 Piping Support In containment. Component EM-03-C033 WO 06-288978-001 VT- 3 SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Piping Support In containment. Component BG-22-H007 WO 08-311169-011 VT- 3 During the review and observation of each examination, the inspectors verified that activities were performed in accordance with ASME Boiler and Pressure Vessel Code requirements and applicable procedures. During the observed nondestructive examinations identified above, three relevant indications were identified (one dye penetrant, one radiograph, and one boric acid leak on the control rod drive mechanism canopy seal weld). Indications identified were dispositioned in accordance with ASME Code and approved procedures. The two weld indications were removed and re-examined. A control rod drive mechanism canopy seal weld clamp was installed. There were no examinations performed where relevant indications had been accepted by the licensee for continued service. The qualifications of all nondestructive examination technicians performing the inspections were verified to be current.

The inspectors directly observed a portion of the following welding activities: SYSTEM WELD IDENTIFICATION WELD TYPE Reactor Coolant Pump Seal Water Reactor coolant pump seal water supply line drain. 1974 foot elevation auxiliary building, letdown heat exchanger room. WO 06-288993-000.

Inlay, Gas Tungsten Arc Welding, hand welded High Pressure Safety Injection System Vent valve. 1974 foot elevation of auxiliary building, area 1.

WO 08-310289-077 Inlay, Gas Tungsten Arc Welding, hand welded Chemical and Volume Control System Vent valve. Reactor water storage tank to centrifugal charging Pump A suction check valve. 1974 foot elevation of auxiliary building, area 1.

WO 08-310289-007 Inlay, Gas Tungsten Arc Welding, hand welded SYSTEM WELD IDENTIFICATION WELD TYPE Essential Service Water System Containment cooler B ESW supply isolation valve (install flanges on pipe for butterfly valve). 2047 foot elevation in containment, near Cooler B duct. WO 07-299593-012. Inlay, Gas Tungsten Arc Welding, hand welded Chemical and Volume Control System Vent valve. Safety Injection Pump Room B Valves BG-V0842 and V0843. 1974 foot elevation of auxiliary building, area 1.

WO 08-310289-043. Inlay, Gas Tungsten Arc Welding, hand welded The inspectors verified, by review, that the welding procedure specifications and the welders had been properly qualified in accordance with ASME Code,Section IX, requirements. The inspectors also verified through record review that essential variables for the welding process were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.01 of Inspection Procedure IP 71111.08.

b. Findings

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

.2 Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)

a. Inspection Scope

The inspectors witnessed the licensee's performance of the required visual inspection (VT-2) of the reactor head and pressure-retaining components above the reactor pressure vessel head in accordance with requirement of ASME Code Case N-729-1 as mandated by 10 CFR 50.55a effective October 10, 2008. Implementation required ASME Code IWA-2212 VT-2 under the mirror insulation on top of the reactor head through multiple access points. The inspectors reviewed the results of this inspection for evidence of leaks or boron deposits at reactor pressure boundaries and related insulation above the head. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.02 of Inspection Procedure PI 71111.08.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)

a. Inspection Scope

The inspectors evaluated the implementation of the licensee's boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspection procedure required review of plant areas that had recently received a boric acid walkdown by the licensee, through either direct observation or record review. The inspectors reviewed the records associated with the licensee's most recent boric acid corrosion control walkdown, as specified in Procedure STN PE-040D, "RCS Pressure Boundary Integrity Walkdown," Revision 3. The inspectors directly observed some of those plant areas recently walked down by the licensee. Additionally, the inspectors independently walked down piping and components containing boric acid inside containment and the auxiliary building. The inspection procedure also required verification that visual inspections emphasize locations where boric acid leaks can cause degradation of safety-significant components. The inspectors verified through record review that the boric acid corrosion control inspection efforts were directed towards locations where boric acid leaks can cause degradation of safety-related components.

The inspection procedure required review of one to three engineering evaluations performed for boric acid found on reactor coolant system piping and components. For those sources of boron leakage identified, the engineering evaluations gave assurance that the ASME Code wall thickness limits were properly maintained. The inspection procedure also required review of one to three corrective actions performed for evidence of boric acid leaks identified. The inspectors confirmed that the work orders and evaluations generated in response to boron leakage identification were consistent with requirements of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.03 of Inspection Procedure IP 71111.08

b. Findings

Introduction.

The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the licensee's failure to identify sources of boron leakage and document them in a corrective action document. Specifically, during a boric acid walkdown, the inspectors identified 11 sources of boron leakage which had not been previously identified and documented by the licensee.

Description.

On October 23, 2009, the inspectors performed a boric acid walkdown of areas inside containment and the auxiliary building. The inspectors identified 11 sources of leakage which had not been previously identified and documented in a corrective action document by the licensee during the licensee's boric acid walkdowns completed on October 11, 2009. With the exception of one leak, the leaks were not active and only had small amounts of boric acid crystals present.

The inspectors noted that those boron leakage sources which were identified during the walkdown inside containment were described by the licensee in the completed walkdown procedure as having no boron indication. The licensee stated that their boric acid inspections were focused on larger amounts of boron leakage and may have been insensitive to smaller amounts of leakage. This is contrary to station Procedure AP 16F-001, "Boric Acid Corrosion Control Program," Revision 5, step 6.4.1, which states that: "Sources of boron seepage/leakage shall be identified/verified and documented in the applicable corrective action document." The licensee entered the missed leakage sources into their corrective action program and initiated a condition report to follow up on the extent of condition of missed boron leakage sources.

Analysis.

The inspectors determined that the failure to identify sources of boron leakage was contrary to station procedures and was a performance deficiency. Specifically, 11 examples of boron leakage were not identified and documented in a corrective action document.

The finding was determined to be more than minor in accordance with Inspection Manual Chapter 0612, Appendix B, "Issue Screening," because it was associated with the human performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, boric acid leakage has historically been found to degrade carbon steel components which could affect the reactor coolant system pressure boundary or impact the reliability of emergency core cooling systems. The inspectors used Inspection Manual Chapter 0609, "Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings," and determined the finding was of very low safety significance (Green) because the issue would not result in exceeding the technical specification limit for identified reactor coolant system leakage or effect other mitigating systems resulting in a total loss of their safety function. The inspectors also determined that the finding had a crosscutting aspect in the area of problem identification and resolution, operating experience, where the licensee did not institutionalizes operating experience through changes to station processes, procedures, equipment, and training programs [P.2.(b)].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," states, in part, that "Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings." Licensee Procedure AP 16F-001,"Boric Acid Corrosion Control Program," Revision 5, which prescribes activities affecting quality, states, in part, that "sources of boron seepage/leakage shall be identified/verified and documented in the applicable corrective action document." Contrary to the above, prior to October 23, 2009, the licensee failed to accomplish the requirements of Procedure AP 16F-001.

Specifically, the licensee failed to identify 11 sources of boron leakage in the containment structure and the auxiliary building and document them in a corrective action document. Because this issue was determined to be of very low safety significance (Green) and was entered into the licensee's corrective action program as Condition Report AR-00021274, this violation is being treated as a noncited violation in accordance with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2009005-03, "Failure to Identify Sources of Boron Leakage."

.4 Steam Generator Tube Inspection Activities (71111.08-02.04)

a. Inspection Scope

The inspection procedure specified performance of an assessment of in situ screening criteria to assure consistency between assumed nondestructive examination flaw sizing accuracy and data from the EPRI examination technique specification sheets. It further specified assessment of appropriateness of tubes selected for in situ pressure testing, observation of in situ pressure testing, and review of in situ pressure test results.

At the time of this inspection, no conditions had been identified that warranted in situ pressure testing. The inspectors reviewed the Licensee's Report SG-CDME-08-15, "Wolf Creek Refueling 16 Condition Monitoring Assessment and Operational Assessment," Revision 1, dated April 2008, and compared the in situ test screening parameters to the guidelines contained in the EPRI document "In Situ Pressure Test Guidelines," Revision 2. This review determined that the remaining screening parameters were consistent with the EPRI guidelines.

In addition, the inspectors reviewed both the licensee site-validated and qualified acquisition and analysis technique sheets used during this refueling outage and the qualifying EPRI examination technique specification sheets to verify that the essential variables regarding flaw sizing accuracy, tubing, equipment, technique, and analysis had been identified and qualified through demonstration. The inspector-reviewed acquisition technique and analysis technique sheets are identified in the attachment.

The inspection procedure specified comparing the estimated size and number of tube flaws detected during the current outage against the previous outage operational assessment predictions to assess the licensee's prediction capability. The inspectors compared the previous outage operational assessment predictions contained in Report SG-CDME-08-15, Revision 1, with the flaws identified thus far during the current steam generator tube inspection effort. Compared to the projected damage mechanisms identified by the licensee, the number of identified indications fell within the range of prediction and was quite consistent with predictions.

The inspection procedure specified confirmation that the steam generator tube test scope and expansion criteria meet technical specification requirements, EPRI guidelines, and commitments made to the NRC. The inspectors evaluated the recommended steam generator tube eddy current test scope established by technical specification requirements. The inspectors compared the recommended test scope to the actual test scope and found that the licensee had accounted for all known flaws and had established a test scope that met or exceeded minimum technical specification requirements, EPRI guidelines, and commitments made to the NRC. The scope of the licensee's Eddy current examinations of tubes in both steam generators included:

• 100 percent, bobbin examination of tubes in steam generators A and D, full length except for rows 1 and 2, which were inspected with the bobbin from tube end to tube support plate 7 from both hot and cold legs

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

• Mid-range +Point examination of 100 percent of the cold leg peripheral tubes in steam generators A and D

• Dings (free span) > 5 volts: inspect 50 percent of all previously identified and new dings >5 volts in the hot leg (including the U-bends) with the mid-range +Point probe in steam generators A and D

• Dents (structures) > 2 volts: inspect 50 percent of all previously identified and new dents >2 volts in the hot leg (including the U-bends) with the mid-range +Point probe in steam generators A and D * +Point examination of all "I-code" indications that were not resolved after history review

• +Point inspection of new wear indications and prior wear indications that have changed by 10 percent through-wall defect or greater in steam generators A and D

• Visual inspection of mechanical and weld plugs

• +Point examination of a five percent sample of bobbin indications that have not changed since the prior inspection (H and S codes) * +Point inspection to bound (all surrounding tubes, at least one pitch removed) the tubes exhibiting possible loose parts signals during the inspection * +Point inspection of a sample of tubes to support the scale profiling effort The results, as known to the inspectors at the conclusion of this inspection, are as follows: For steam generator A, 6 tubes with wear indication of 40 percent through-wall defect or greater at one or more anti-vibration bar intersections were plugged. Additionally, one tube was conservatively plugged for a geometric anomaly. This tube did not exhibit any cracking characteristic after analysis of the +Point and Ghent probe data.

For steam generator D, 10 tubes with wear indication of 40 percent through-wall defect or greater at one or more anti-vibration bar intersections were plugged. Additionally, one tube was conservatively plugged for a geometric anomaly. This tube did not exhibit any cracking characteristic after analysis of the +Point and Ghent probe data. The inspection procedure specified that, if new degradation mechanisms were identified, the licensee would verify the analysis fully enveloped the problem of the extended conditions including operating concerns and that appropriate corrective actions were taken before plant startup. No new degradation mechanisms were identified by the eddy current examination results.

The inspection procedure required confirmation that the licensee inspected all areas of potential degradation, especially areas that were known to represent potential eddy current test challenges (e.g., top of tube sheet, tube support plates, and U-bends). The inspectors confirmed that all known areas of potential degradation were included in the scope of inspection and were being inspected. The inspection procedure further required verification that repair processes being used were approved in the technical specifications. At the completion of the inspection, the inspectors were informed that 18 tubes were to be plugged. The inspectors verified that the mechanical expansion plugging process used was an NRC-approved repair process.

The inspection procedure also required confirmation of adherence to the technical specification plugging limit, unless alternate repair criteria had been approved. The inspection procedure further requires determination whether depth sizing repair criteria were being applied for indications other than wear or axial primary water stress corrosion cracking in dented tube support plate intersections. The inspectors determined that the technical specification plugging limits were being adhered to (i.e., 40 percent maximum through-wall indication).

If steam generator leakage greater than three gallons per day was identified during operations or during post shutdown visual inspections of the tube sheet face, the inspection procedure required verification that the licensee had identified a reasonable cause based on inspection results and that corrective actions were taken or planned to address the cause for the leakage. The inspectors did not conduct any assessment because this condition did not exist.

The inspection procedure required confirmation that the eddy current test probes and equipment were qualified for the expected types of tube degradation and an assessment of the site-specific qualification of one or more techniques. The inspectors observed portions of eddy current tests performed on the tubes in steam generators A and D. During these examinations, the inspectors verified that:

(1) the probes appropriate for identifying the expected types of indications were being used,

(2) probe position location verification was performed,

(3) calibration requirements were adhered to, and

(4) probe travel speed was in accordance with procedural requirements. The inspectors performed a review of site-specific qualifications of the techniques being used. These are identified in the attachment.

The inspection procedure specified that if loose parts or foreign materials were identified on the secondary side, the inspectors should review the licensee's evaluation of the materials and/or complete appropriate repairs of affected steam generator tubes. Additionally, the licensee should either remove accessible foreign objects or perform an evaluation of the potential effects of inaccessible object migration and tube fretting damage. During this inspection, 18 small foreign objects were found in steam generator A; of these, 7 items were retrieved. There were 34 small foreign objects found in steam generator D; of these, 18 items were retrieved. These objects, small wires and sludge rocks, were prioritized and retrieved based on their potential to damage the steam generator tubes in accordance with Refuel Outage 17 Degradation Assessment and EPRI 1019039, "Steam Generator Management Program: Foreign Object Prioritization Strategy for Square Pitch Steam Generators." Those items not removed from the steam generators were evaluated and determined to have no ability to damage the steam generator tubes during operation. Condition Report AR-00021178 documents the foreign objects in the licensee's corrective action program. The required chemical and mechanical effects of these remaining pieces were analyzed with the conclusion of negligible effects on the respective steam generators. Work Orders 09-321481-000 and 09-321386-000 evaluated the acceptability of the steam generators with these minor foreign objects remaining.

Finally, the inspection procedure specified review of one-to-five samples of eddy current test data if questions arose regarding the adequacy of eddy current test data analyses. The inspectors did not identify any results where eddy current test data analyses adequacy was questionable.

These actions constitute completion of the requirements for Section 02.04 of Inspection Procedure IP 71111.08.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems (71111.08-02.05)

a. Inspection Scope

The inspection procedure required review of a sample of problems associated with inservice inspections documented by the licensee in the corrective action program for appropriateness of the corrective actions.

The inspectors reviewed nine condition reports which dealt with inservice inspection activities and found the corrective actions were appropriate. The specific condition reports reviewed are listed in the documents reviewed section. From this review, the inspectors concluded that the licensee has an appropriate threshold for entering issues into the corrective action program and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying industry operating experience. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.05 of Inspection Procedure IP 71111.08.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

There were no opportunities to inspect operator requalification in the fourth quarter.

There were zero activities completed for quarterly licensed-operator requalification as defined in Inspection Procedure IP 71111.11.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• October 27, 2009, 125Vdc nonsafety-related PK system

• December 17, 2009, Component cooling water system

• December 18, 2009, Source range neutron monitors

• October 6, 2009, Residual heat removal system

• December 21, 2009, Offsite power supplies

• December 22, 2009, Intermediate range neutron monitors The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

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

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

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

• Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1) The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of six quarterly maintenance effectiveness samples as defined in Inspection Procedure IP 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• November 20, 2009, Emergent work on control room door ventilation boundary

• October 15, 2009, Corrosion on containment cooler A

• October 13, 2009, Emergent work on annunciator power supply failures

• October 10 to November 17, 2009, Shutdown risk assessments

• November 18, 2009, Technical Specification 3.0.4.b risk assessment for Mode 4 to Mode 3

• November 23, 2009, Emergent work for oil loss from centrifugal charging pump A The inspectors selected these activities based on potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of three maintenance risk assessments and emergent work control inspection sample as defined by Inspection Procedure IP 71111.13-05.

b. Findings

===.1

=

The inspectors identified a Green noncited violation of 10 CFR 50.65(a)(4) involving the failure to adequately perform shutdown risk assessments during Refueling Outage 17.

Description.

While reviewing daily risk assessments during Refueling Outage 17, the inspectors noted discrepancies in the calculation of the risk conditions of the shutdown safety function condition. As a result, the inspectors reviewed the AP 22B-001, "Outage Risk Assessment," and Form APF 22B-001-02, "Daily Shutdown Risk Assessment." Wolf Creek uses Procedure AP 22B-001, to implement the requirements of 10 CFR 50.65(a)(4) during shutdown conditions (Modes 4, 5, 6, and defueled). In the references section, the procedure lists NUMARC 93-01, Section 11, "Assessment of Risk Resulting from Performance of Activities," as well as Regulatory Guide 1.182 in which the NRC endorses NUMARC 93-01, Section 11, dated February 2000. Wolf Creek has no NRC approved exceptions to Regulatory Guide 1.182. NUMARC 93-01, Section 11.3.5, provides a scope of five key Shutdown Safety Functions: decay heat removal capability, inventory control, electric power availability, reactivity control, and containment. Sections 11.3.6.1 through 11.3.6.5 provide specifics for each shutdown function. Overall, the inspectors found several examples in which the five aspects NUMARC 93-01, Section 11, were not correctly implemented for risk assessments. Form APF 22B-001-02 defines Condition 3 or High Risk as only one safety train is available to satisfy the shutdown safety function. In the examples below, this contradicted with Wolf Creek's actions. For the "Decay Heat Removal" Shutdown Safety Function, Procedure APF 22B-001-02 did not direct consideration of containment closure time per NUMARC 93-01, Section 11.3.6.1. The inspectors cross-referenced the daily shutdown risk assessment forms with the equipment out-of-service list maintained in the control room log and found three such instances of this occurring. First, on October 16 and 17, 2009, during the core offload, the reactor building equipment hatch was listed as closed during fuel movement; however, the equipment out-of-service list showed the equipment hatch as open from October 10 through November 15, 2009. Secondly, from October 14-17, 2009, and again on November 5-11, 2009, the reactor building auxiliary access hatch was on the equipment out-of-service list because the interlocks were defeated to install a temporary closure device. The daily risk assessment did not analyze this condition which had the potential to impact the outcome of the risk assessment. The third instance occurred on November 16, 2009, when the reactor building personnel hatch failed to meet the surveillance requirement acceptance criteria. This was also not analyzed for its effect on containment closure. For the "(Electric) Power Availability" Shutdown Safety Function, Procedure APF 22B-001-02 did not explicitly direct consideration of ac and dc instrumentation and control power availability per NUMARC 93-01, Section 11.3.6.3. The inspectors cross-referenced the daily shutdown risk assessment forms with the equipment out-of-service list maintained in the control room log archive and found two such instances of this occurring. First from October 19 through 25, 2009, the 125Vdc 60-Cell Battery 4 was inoperable pending further analysis due to positive plate material separation identified during a visual inspection. The corresponding NK04 electrical bus was incorrectly considered available on the six daily risk assessments performed during that time period. The second instance occurred on November 6 through 10, 2009, when the 125Vdc 60-Cell Battery 3 inoperable pending further analysis due to several cell abnormalities identified during a visual inspection. The corresponding NK03 electrical bus was incorrectly considered available on the five daily risk assessments performed during that time period. Furthermore, these dc power unavailabilities were listed on the risk assessment, but were not factored into its outcome (or color).

For the "Containment" Shutdown Safety Function, Procedure APF 22B-001-02 did not direct consideration of the availability of ventilation and radiation monitoring equipment with respect to the filtration and monitoring of releases per NUMARC 93-01, Section 11.3.6.5. The inspectors again cross-referenced the daily shutdown risk assessment forms with the equipment out-of-service list maintained in the control room log and identified two such instances of this occurring. The first instance occurred during core offload on October 17, 2009. At that time, the availability of Containment Atmospheric Radiation Monitor GTRE0031 was degraded because it was being powered by temporary power. The normal source, safety bus NB02, was de-energized for maintenance from October 17 through 25, 2009. The second instance occurred during core reload on November 5 and 6, 2009, when the GTRE0021B was removed from service from October 29 through November 28, 2009, per the equipment out-of-service list. Neither of these components was listed in the daily risk assessment, nor was their impact quantified in the determination of the risk level (or color).

For the "Decay Heat Removal" Shutdown Safety Function, only residual heat removal and steam generators can actually perform the function of heat removal. The risk assessments credited reactor cavity level greater than 23 feet above the vessel flange and a greater than 4-hour time to boil in the decay heat removal function. Thus, this configuration would be a permissible, moderate risk condition even if there were no active means of removing heat from the reactor. The inspectors cross-referenced the daily shutdown risk assessment forms with the equipment out-of-service list and identified two instances of this occurring. First, on October 10, 2009 at 10:29 a.m., and again on November 13 through 17, 2009, the risk assessments specified that steam generators were available for heat removal when the auxiliary feedwater system was unavailable because its safety-related water source (essential service water) was isolated by Clearance Order C17-R-OP-S-005. Steam generators were available for reflux cooling. Wolf Creek credits reflux cooling using EPRI Technical Report 102972, "Reflux Cooling: Application to Decay Heat Removal During Shutdown Operations." The earliest EPRI analyzed scenario is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after shutdown; however, on October 10, 2009, only 10.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following shutdown, the decay heat load would be significantly higher and warrant further analysis. The inspectors concluded that since this condition was unanalyzed, it could not be credited and a steam generator feedwater source would be required for such a short time after reactor shutdown. The decay heat removal Shutdown Safety Function was categorized as normal risk (green) when it should have been moderate risk (yellow) for the two risk assessments performed on October 10, 2009. The other risk assessments that use reflux cooling were bounded by the EPRI analysis. Lastly, the inspectors reviewed spent fuel pool cooling on October 30, 2009. The risk assessment form specified one train was available and resulted in moderate risk (yellow); however, red risk was defined as one safety train available for the function. Although not an input to the color, the form specified normal and alternate makeup water sources to the spent fuel pool. Inspectors interviewed senior operators to identify the normal and alternate sources. One indicated that the refueling water storage tank through the spent fuel pool transfer pumps was the normal source. Another indicated demineralized water was the makeup source. For the alternate makeup source, one indicated essential service water while another stated it was fire water. In any case, none of the sources were specified and tracked by the risk assessment form to mitigate the loss of one fuel pool cooling train. For the "[Electric] Power Availability" Shutdown Safety Function, a loss of offsite power, or loss of both diesel generators, combined with no switchyard activities is categorized as a low risk condition. Furthermore, a station blackout with no switchyard activities in progress is a moderate risk condition. Inspectors found that this resulted in an inadequate risk assessment for electrical power in that the risk assessment would permit shutdown activities without any available sources of ac power. Wolf Creek categorized one in-service power source as moderate risk (yellow) rather than high risk. This was in contrast to the definition of high risk in which only one safety train available to satisfy the function. The inspectors cross-referenced the daily shutdown risk assessment forms with the equipment out-of-service list maintained in the control room log and found that on November 8, 2009, at 8:57 a.m. the risk assessment listed two diesel generators as being available; however, the equipment out-of-service list indicated that emergency diesel generator A was out of service because essential service water train A was unavailable from November 5, 2009, at 4:37 a.m. until November 8, 2009, at 1:30 p.m.

When the credit for emergency diesel generator A is removed, the risk assessment outcome changes from normal risk (green) to moderate risk (yellow). The second instance occurred for the daily risk assessment performed between October 31 and November 4, 2009, which lists two diesel generators as being available. However, the equipment out-of-service list indicated that emergency diesel generator B was out of service because essential service water Train B was unavailable from October 16, 2009, at 10:05 p.m. until November 5, 2009, at 4:19 a.m. On all five daily risk assessments performed between October 31 and November 4, 2009, if the credit for the second diesel generator were removed, the outcome of the risk assessment changed from normal risk to moderate risk.

Analysis.

The failure to meet shutdown risk assessment requirements in the shutdown risk assessment process is a performance deficiency. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC's regulatory function, and the finding was not the result of any willful violation of NRC requirements or Wolf Creek procedures. The inspectors determined that this finding impacted the Mitigating Systems Cornerstone and was more than minor because it involved incorrect risk assessments that changed the outcome or color of the assessments. Per Inspection Manual Chapter 0609, Appendix K, "Maintenance Risk Assessment and Risk Management Significance Determination Process," licensees who only perform qualitative analyses of plant configuration risk due to maintenance activities, the significance of the deficiencies must be determined by an internal NRC management review using risk insights where possible in accordance with Inspection Manual Chapter 612, "Power Reactor Inspection Reports." The NRC management review concluded that this finding was of Green safety significance because missing risk management actions did not result in loss of key shutdown risk functions. Additionally, the cause of the finding has a human performance crosscutting aspect in the area associated with the resources. Specifically, Wolf Creek did not ensure that Procedure APF 22B-001-02 was complete, accurate, and up-to-date H.2(c).

Enforcement.

Title 10 CFR 50.65(a)(4) states, in part, that before performing maintenance activities (including but not limited to surveillance, postmaintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, between October 10, and November 17, 2009, Wolf Creek did not appropriately assess and manage the increase in risk resulting from proposed maintenance activities. Specifically, Form APF 22B-001-02 did not appropriately consider electrical power, decay heat removal, and containment when assessing shutdown risk. Because the finding is of very low safety significance and has been entered into the corrective action program as condition reports 22295 and 22296, this violation is being treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-04, "Failure to Incorporate Requirements of Regulatory Guide 1.182 into Daily Shutdown Risk Assessments."

===.2

=

On November 18, 2009, the inspectors identified a Green noncited violation of Technical Specification 3.0.4.b for ascension from Mode 4 to Mode 3 without establishing required risk management actions.

Description.

On the morning of November 18, 2009, the turbine-driven auxiliary feedwater pump was inoperable per technical specification 3.0.4.b as specified in the control room log at 11:53 p.m. the previous day upon ascension from Mode 4 into Mode 3 at 12:24 a.m. Technical specification 3.0.4.b permits mode ascension after performance of a risk assessment to address the inoperable components and consideration and implementation of risk management actions to maintain safety in the next mode. This condition is permissible for auxiliary feedwater per Technical Specification LCO 3.7.5 so long as the ascension is below Mode 1. The entry was made using an operational risk assessment Form APF 22C-003-01 in accordance with Technical Specification LCO 3.0.4.b. The risk assessment on November 17, 2009, specified: 1. The turbine-driven auxiliary feedwater pump restoration following Surveillance Requirement 3.7.5.2, completion is expected within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of entering Mode 3. 2. As a compensatory measure [risk management action], protected train signs would be placed on the doors to the motor-driven auxiliary feedwater pumps A and B room doors. A walkdown conducted by the inspector at 10:30 a.m. on November 18, 2009, found that the protected train signs on the motor-driven auxiliary feedwater pump rooms specified by the operational risk assessment were not in place. Also, a maintenance crew was performing radiography in the motor-driven auxiliary feedwater pump Room B. A further review of the control room logs revealed that motor-driven auxiliary feedwater pump comprehensive pump testing, flow path verification, and containment isolation valve verification testing were scheduled and performed, making both motor-driven auxiliary feedwater pumps A and B inoperable (at separate times) during the morning of November 18, 2009, while turbine-driven auxiliary feedwater was still inoperable. Operators did make proper entry into Technical Specification 3.7.5, Condition C, for two of three auxiliary feedwater trains inoperable; however, this configuration was not analyzed in the risk assessment. Immediately following the walkdown, the inspector discussed the issue with the shift manager, the protected train signs were installed on the motor-driven auxiliary feedwater pump room doors and a condition report was initiated. Wolf Creek determined that an informal mode ascension check off list was used that conflicted with the risk assessment performed for Technical Specification 3.0.4.b.

Analysis.

Mode ascension under Technical Specification LCO 3.0.4.b without establishing required risk management actions is a performance deficiency. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC's regulatory function, and the finding was not the result of any willful violation of NRC requirements or Wolf Creek procedures. The inspectors determined that the violation was more than minor because it was associated with the configuration control and alignment attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The configuration control issues not only included the work being completed on the turbine-driven auxiliary feedwater pump, but also included containment isolation valve testing and radiography that was performed on the motor-driven auxiliary feedwater pumps which was not included in the risk assessment. The inspector used Inspection Manual Chapter 0609.04, "Phase 1 SDP - Worksheet," to determine that the finding was of very low safety significance (Green) because it did not result in a loss of system safety function; exceed allowable technical specification outage time; and was not a seismic, flooding, or severe weather concern. Additionally, the cause of the finding has a human performance crosscutting aspect in the area associated with the decision making. Specifically, Wolf Creek used a risk assessment form and informal mode change form to communicate between departments the requirement for risk management actions. The two forms were in conflict, and the personnel who implemented the risk management actions were not informed H.1(c).

Enforcement.

Wolf Creek Technical Specification LCO 3.0.4.b states, in part, "When an LCO is not met, entry into a MODE or other specified condition in the Applicability shall only be made after performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate." Prior to MODE ascension with the turbine-driven auxiliary feedwater pump inoperable, Wolf Creek performed a risk assessment and identified risk management actions. Contrary to the above, on November 18, 2009, at 12:24 a.m. Wolf Creek invoked Technical Specification 3.0.4.b to ascend from Mode 4 to Mode 3 without implementing the risk management actions required by the risk assessment performed to justify the Mode change with the turbine-driven auxiliary feedwater pump inoperable. Because the finding is of very low safety significance and has been entered into the corrective action program as Condition Report 00021926, this violation is being treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-05, "Mode Change under Technical Specification 3.0.4.b Without Required Risk Management Actions."

===.3

=

On October 15, 2009, the inspectors identified a violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for failure to follow Procedure AP 28A-100, "Condition Reports." Wolf Creek failed to initiate a condition report for evaluation of corrosion on containment cooler A piping.

Description.

On October 15, 2009, the inspectors identified dried white and brown deposits on vertical piping from insulation seams on containment cooler A. The inspectors identified the condition to Wolf Creek. On October 17, Wolf Creek completed Work Order 09-321113-000 to remove the insulation and found significant corrosion of piping and flanges for containment cooler A. Work Order 09-321113-000 stated that the cause of the corrosion was unknown. Wolf Creek informed the inspectors that the cause of the corrosion was condensation. The inspectors noted that since no ultrasonic testing had been performed, leakage from through-wall defects could not be eliminated as a cause. Wolf Creek later informed the inspectors that the visual inspection showed no through wall defects. The inspectors again challenged Wolf Creek since no ultrasonic testing was performed to demonstrate that through wall defects could be eliminated as a cause. The inspectors reviewed Procedure AP 28A-100, "Condition Reports," Revision 10, Attachment C. Attachment C required condition reports when equipment issues require evaluation beyond the work controls (work order) process. Procedure AP 28A-100 defines an adverse condition as one that could impact nuclear safety. Wolf Creek subsequently initiated Condition Report 20964 on October 21, 2009, stating that there was extensive corrosion on containment cooler A and that all containment coolers could be affected. Condition Report 20964 went on to evaluate the piping insulation and how it did not prevent condensation on the piping which allowed the corrosion. On October 23 and October 26, Wolf Creek initiated several work requests to perform ultrasonic testing of containment coolers A, B, and C. Wolf Creek initiated the work order to perform piping and flange thickness measurements which were found to be satisfactory. Wolf Creek engineering determined that containment coolers A, B, and C had piping flange studs that needed to be replaced due to corrosion. From November 1 to November 2, a total of 32 studs and 96 nuts were replaced for the three coolers. On November 8 and 11, 2009, Wolf Creek completed engineering dispositions to address the cause and the results of the ultrasonic testing. Condition Report 22443 also identified the need for more ultrasonic inspections in the next refueling outage to verify acceptable corrosion rates. On December 16, 2009, Wolf Creek initiated Condition Report 22443 which described the lack of a timely condition report to determine a cause of the corrosion.

Analysis.

The inspectors determined that the failure to follow Procedure AP 28A-100, Appendix C, was a performance deficiency. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC's regulatory function, and the finding was not the result of any willful violation of NRC requirements or Wolf Creek procedures. This issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, the issue screened to Green because there was not a loss of operability and the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. A crosscutting aspect was identified in the problem identification and resolution area of the corrective action program. Specifically, Wolf Creek failed to implement a corrective action program with a low threshold for identifying issues P.1.a].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality be described by documented instructions, procedures or drawings appropriate to the circumstances and be accomplished in accordance with these instructions, procedures or drawings. Procedure AP 28A-100, Attachment C, "Equipment Problems Requiring a Condition Report," requires, in part, that condition reports be written where further evaluation is needed outside the work control process. Contrary to the above, from October 15 to 23, 2009, Wolf Creek failed to complete an activity affecting quality in accordance with documented procedures appropriate to the circumstances. Specifically, Wolf Creek failed to write a condition report for corrosion on containment cooler A after Work Order 09-321113-000 stated that the cause of the corrosion was unknown. Because this violation was determined to be of very low safety significance and was placed in the corrective action program as Condition Reports 20964 and 22443, this violation is being treated as a noncited violation in accordance with Section VI.A.1 of the Enforcement Policy: NCV 05000482/2009005-06, "Failure to Follow Corrective Action Procedure."

===.4

=

On November 23, 2009, a self-revealing violation of Technical Specification 5.4.1.a was reviewed by the inspectors after a technician failed to follow procedures and emptied 45 gallons of oil from centrifugal charging pump A.

Description.

On November, 23, 2009, a technician loosened the wrong nut and removed the thermowell for Temperature Indicator BG TI-0036 on centrifugal charging pump A. At the time, the auxiliary lube oil pump was running. The auxiliary lube oil pump normally runs while the pump is in standby. This emptied 45 gallons of oil from the pump. Removal of the temperature indicator normally would not affect operability since the oil temperature indication is not required; however, the pump cannot function without lube oil. Control room operators declared the pump inoperable and entered Technical Specification 3.5.2. Approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> later, the thermowell and oil were replaced, the pump was leak tested and Technical Specification 3.5.2, Condition A was exited.

Wolf Creek performed a root cause analysis for this issue under Condition Report 21993.

During interviews, the technician stated that he performed a 2 minute self-check (a recognized error reduction technique at Wolf Creek) but failed to identify the correct nut to loosen. This task is a required training task for these temperature indicators, which involves a similar training rig. The technician stated that he understood the difference between the thermowell nut and the temperature indicator but failed to make the differentiation on November 23. The technician and the supervisor discussed the work, but the communication was inadequate because the technician was left with the idea to perform the work independently, and the supervisor believed that the technician was only going to perform a walkdown of the indicator. The prejob briefing standard at Wolf Creek required supervisor approval for a self-briefing.

Analysis.

The failure to follow Procedure STN IC-294A and correctly remove the detector was considered a performance deficiency. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC's regulatory function, and the finding was not the result of any willful violation of NRC requirements or Wolf Creek procedures. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and it affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," and determined that the finding was of very low safety significance (Green) because the pump was inoperable for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Also, the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors identified a human performance crosscutting in the area of work practices because a 2-minute self-check and communication with the supervisor failed to prevent the event H.4.a].

Enforcement.

Technical Specification 5.4.1.a requires the implementation of written procedures described in Regulatory Guide 1.33, Revision 2, Appendix A. Section 9.A of Regulatory Guide 1.33 requires procedures for performing maintenance that can affect the performance of safety-related equipment. Procedure STN IC-294A, "Calibration of CCP A Outboard Bearing and Lube Oil Supply Temperature Indicators BGTI0036 and BGTI0040," Revision 0, step 8.2.1, requires that the temperature detector be removed from its thermowell for calibration. Contrary to the above, on November 23, 2009, a worker removed the thermowell and breached the lube oil subsystem. Because this violation was determined to be of very low safety significance and was placed in the corrective action program as Condition Report 21993, this violation is being treated as a noncited violation in accordance with Section VI.A.1 of the Enforcement Policy:

NCV 05000482/2009005-07, "Failure to Follow Procedure Results in Draining of Emergency Core Cooling System Pump Oil."

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• October 9, 2009, Source range nuclear instrument (NI)-31 response

• November 5, 2009, Essential service water pump seismic operability The inspectors selected these potential operability issues based on the risk-significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and USAR to the licensee's evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of three operability evaluations inspection samples as defined in Inspection Procedure IP 71111.15-05

b. Findings

===.1

=

On November 5, 2009, the inspectors identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings,"

for failure to perform an adequate operability evaluation as required by procedure.

Description.

On November 1, 2009, Wolf Creek was defueled for Refueling Outage 17, and essential service water pump A was being replaced. On November 1, 2009, Wolf Creek found that the as-constructed clearances at the essential service water pump A flange did not meet design requirements. This allowed the pump column to flex up to 0.125 inches until it would engage the seismic supports. The pumps were designed to be rigidly restrained. This resulted in Condition Reports 21400 and 21572. Wolf Creek completed Operability Evaluation EF-09-010 that provided the basis for the past operability of essential service water Pump A and future operability of essential service water pump B on November 1, 2009, and initiated Condition Report 22400 to correct the clearances. On November 5, 2009, the inspectors reviewed Operability Evaluation EF-09-010. The evaluation concluded that the increased movement of the pump would increase stresses to 10 ksi, which was below the specified allowable ASME Code Section III limit of 17.5 ksi. The evaluation identified requirements that the pumps shall operate during and after a safe shutdown earthquake as one of the design basis functions as required per 10 CFR Part 50, Appendix A, General Design Criterion 2. These seismic design requirements are contained in Sections 3.9(B) and 9.2.1 of the USAR. The inspectors found that the operability evaluation's technical basis was inadequate due to the following:

(1) the evaluation did not contain a formal calculation that demonstrated that stresses were below limits,

(2) the evaluation only considered operating basis earthquake accelerations and not the larger safe shutdown earthquake accelerations,

(3) the evaluation did not contain a calculation to demonstrate that the pump impeller clearances were allowable if an earthquake occurred while the pump was running, and

(4) the method of analysis for the stresses was not described as an appropriate alternative method to the original stress calculation done with the SAP V computer program. The inspectors could not verify that the simplified method was appropriate.

The inspectors reviewed Procedure AP 26C-004, "Technical Specification Operability," Revision 20 and Procedure AP 28-001, "Operability Evaluations," Revision 17. Procedure AP 26C-004, step 6.2.6, states that documentation for prompt operability evaluations shall include information needed to support operability. Step 4.5 states that safety functions specified in the current licensing basis shall be met. Procedure AP 28-001, "Operability Evaluations," step 4.9, also describes that the specified safety functions in the current licensing basis shall be met. Step 6.1.7 states that design basis events and safety evaluations should be considered. There is no description of the use of alternative analysis methods in AP 28-001 or AP 26C-004 that is consistent with Regulatory Information Summary 2005-20, Section C.4. On November 7, 2009, Wolf Creek initiated Condition Report 21572 to resolve the items identified above. Wolf Creek completed Operability Evaluation EF-09-010, Revision 1, on December 14, 2009. The inspectors reviewed Revision 1 and determined the above identified deficiencies still existed. Wolf Creek performed a third revision to Operability Evaluation EF-09-010 and initiated Condition Report 22798. The four items were resolved with Operability Evaluation EF-09-010, Revision 2 which contained drawings and calculations to demonstrate that the pumps were seismically qualified and that the simplified calculations were appropriate. In Revision 2, the calculated stresses increased to 16.4 ksi but were still below the limit of 17.5 ksi.

Analysis.

The failure to perform an adequate operability evaluation per Procedures AP 28-001 and AP 26C-004, was a performance deficiency. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC's regulatory function, and the finding was not the result of any willful violation of NRC requirements or Wolf Creek procedures. The inspectors determined that this finding was more than minor because it is associated with the equipment performance attribute for the Mitigating Systems Cornerstone, and it affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, this issue relates to the availability and reliability examples of the equipment performance attribute because a latent common mode failure mechanism was not correctly evaluated. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At Power Situations," and determined that the finding was of very low safety significance (Green) because the issue was not a design or qualification deficiency confirmed to result in loss of operability or functionality, did not represent a loss of system safety function, an actual loss of safety function of a single train for greater than its technical specification allowed outage time, an actual loss of safety function of a nontechnical specification risk-significant equipment train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The cause of the finding has a problem identification and resolution crosscutting aspect in the area associated with the corrective action program because Wolf Creek failed to thoroughly evaluate the failure mechanism such that the resolutions address the causes and extent of conditions, as necessary P.1.c].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality shall be prescribed by documented instructions or procedures of a type appropriate to the circumstances, accomplished in accordance with those instructions or procedures, and contain acceptance criteria to demonstrate that the activity was successfully accomplished.

Procedure AP 26C-004, "Technical Specification Operability," Revision 20, implements this requirement and states, in part, that continued operability decisions shall be made in accordance with Procedure AP 28-001, "Operability Evaluations," Revision 17. Procedure AP 28-001 requires, in part, that operability evaluations shall demonstrate that equipment meets its design functions. Per Sections 3.9(B) and 9.2.1 of the USAR, the essential service water pumps are designed to withstand a safe shutdown earthquake. Contrary to the above, from November 1, 2009, to January 13, 2010, Operability Evaluation EF-09-010, Revisions 0 and 1, did not demonstrate that the essential service water pumps could withstand a safe shutdown earthquake. Specifically, no calculations existed to demonstrate allowable stresses and pump impeller clearances. Because the finding is of very low safety significance and has been entered into the corrective action program as Condition Reports 22798 and 21572, this violation is being treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-08, "Inadequate Operability Evaluation of Essential Service Water Pumps."

===.2

=

The inspectors identified a Green, noncited violation of Technical Specification 3.3.1, Condition I, for making positive reactivity addition prohibited by technical specifications in Mode 2 because one source range nuclear instrument channel was inoperable.

Description.

On August 19, 2009, at 3:47 p.m., a loss of offsite power and reactor trip occurred. As a result, cavity cooling fans were lost causing an increase in air temperature in the reactor cavity. Shortly thereafter, the indicated count rate on source range nuclear instrument NI-31 began increasing from the expected value of about 250 counts per minute (cpm) to 15,000 cpm and then to a maximum of 27,000 cpm over an 8-hour period. Control room operators declared the source range channel NI-31 inoperable as a result of this abnormal behavior. Power to the cavity fans was restored around 1 a.m. on August 20, 2009, and the source range nuclear instrument NI-31 count rate returned to its expected value below 250 cpm, based on its anticipated reading relative to source range NI-32 which did not experience any increase in count rate with a loss of cavity cooling. Wolf Creek concluded, based on feedback from the vendor, the most likely cause of the abnormal readings was moisture intrusion at the cable to detector connection at the base of the detector inside the reactor cavity. As long as cavity cooling remained available, the moisture intrusion would not be an issue. Based on this information, Wolf Creek declared the source range NI-31 operable restarted from the forced outage on August 23, 2009. Wolf Creek's operability evaluation failed to identify that safety-related equipment was now reliant on nonsafety cavity cooling fans and nonsafety electrical power to those fans. The source range instruments NI-31 and -32 are required to be operable in Mode 2 below the P-6 interlock to monitor the approach to criticality. During this time, the resident inspectors questioned the operability of source range instrument NI-31. When entering Refueling Outage 17, a power supply failure in the control cabinet caused source range NI-31 to fail upon demand during shutdown. On October 7, 2009, Wolf Creek performed another operability evaluation that stated that the source range was operable because it had passed its surveillance tests during the last refueling outage that ended in May 2008. The inspectors noted that this evaluation did not address the observed problem and therefore did not provide a reasonable basis for operability. On October 28, 2009, during interviews with Wolf Creek engineering personnel, the inspectors learned that the original operability determination used to restart from the forced outage was inaccurate because the equipment configuration in the field was different than described in the operability determination. The detectors are in fact hard wired and there are no cabling connections until the containment bio-shield wall, therefore, no connectors would be affected by the reactor cavity temperature increase following the loss of cavity cooling fans. Consequently, there was no valid explanation for the increase in count rate observed on August 19, 2009. Shortly thereafter, Wolf Creek replaced the source range NI-31 detector before restart from Refueling Outage 17 to definitively restore operability to the channel. On November 13, 2009, the resident inspectors observed the removal of source range Detector SE-0031 from the reactor cavity. There was some minor damage to the outer layer of cable wrap, however, nothing was observed that could conclusively explain the detector's malfunction on August 19, 2009, or ensure its future operability. Wolf Creek USAR, Chapter 15, credits low power reactor trips as being terminated by the power range instruments. The power range instruments are not required to be operable in Mode 3. USAR, Chapter 15, credits the source range and intermediate range reactor trips to stop reactivity excursions at a much lower power. This allows technical specifications to credit these trips in Mode 3. During the shutdown in August 2009, rod drive motor-generator set testing was performed which cycled the reactor trip breakers and made the control rods capable of withdrawal. The inspectors also reviewed the technical specification bases for the source range which stated that they are required to perform a monitoring function of neutron levels and provide indication of reactivity changes that may occur.

Analysis.

Reactivity addition with source range channel nuclear instrument-31 inoperable is a performance deficiency. The finding was more than minor because it was associated with the configuration control (reactivity control) attribute of the Barrier Integrity Cornerstone, and it affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609.04, and determined that the finding screened to Green because the finding only affected the fuel barrier. Additionally, the cause of the finding has a human performance crosscutting aspect in the area associated with the decision making. Specifically, Wolf Creek did not use conservative assumptions in decision making and adopt requirements to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action, when performing an operability evaluation for the source range Nuclear Instrument 31 detector prior to restarting from a forced outage H.1(b).

Enforcement.

Wolf Creek Technical Specification LCO 3.3.1 "Reactor Trip System Instrumentation," Condition I, requires immediate suspension of all operations activities involving positive reactivity additions when one source range channel is inoperable while in Mode 2. Contrary to the above on August 22, 2009, at 11:10 a.m., Wolf Creek entered Mode 2 with one source range channel inoperable and continued withdrawing control rods until the reactor was critical at 11:54 a.m. At that time, Wolf Creek went above the P-6 interlock and source range monitoring was no longer required by technical specifications. Because the finding is of very low safety significance and has been entered into the corrective action program as Condition Report 20208, this violation is being treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-09, "Positive Reactivity Addition Prohibited by technical specifications while in Mode 2."

1R18 Plant Modifications

Permanent Modifications The inspectors reviewed key affected parameters associated with energy needs, materials, replacement components, timing, heat removal, control signals, equipment protection from hazards, operations, flow paths, pressure boundary, ventilation boundary, structural, process medium properties, licensing basis, and failure modes for the permanent modifications listed below.

• December 16, 2009, Instrument setpoints for reactor coolant pump thermal barrier isolation and Valve EGHV62 The inspectors reviewed key parameters associated with energy needs, materials, replacement components, timing, heat removal, control signals, equipment protection from hazards, operations, flow paths, pressure boundary, ventilation boundary, structural, process medium properties, licensing basis, and failure modes for the permanent modification identified as configuration Change Package 013096.

The inspectors verified that modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure actions, key safety functions, or operator response to loss of key safety functions; postmodification testing will maintain the plant in a safe configuration during testing by verifying that unintended system interactions will not occur; systems, structures and components, performance characteristics still meet the design basis; the modification design assumptions were appropriate; the modification test acceptance criteria will be met; and licensee personnel identified and implemented appropriate corrective actions associated with permanent plant modifications. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

Introduction.

On December 16, 2009, inspectors identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," involving failure to obtain vendor design data for a modification.

Description.

On December 16, 2009, the inspectors reviewed configuration change Package 013096 from August 2009 which modified the upper flow limit through the reactor coolant pump thermal barrier heat exchangers from 60 to 68 gpm. The change package cited an internal memo from 1992 as the justification for the increased flow. The inspectors reviewed the internal memo and noted that it described the thermal barrier outlet valves' going closed on high flow. It also indirectly described a telephone conversation with a Westinghouse representative who stated that the thermal barriers were capable of up to 90 gpm sustained flow. The inspectors found no accompanying data from Westinghouse to justify this claim. Procedure AP 05-005, "Design Control," required that vendor data be obtained in accordance with Procedure AP 05-013, "Review of Vendor Technical Documents," Revision 7A. The inspectors reviewed Procedure AP 05-013 and noted that it stated that documentation would be obtained from the vendor consistent with procurement standards for acceptance.

Procedure AP 05-013, step 6.5, specified evaluation of vendor technical documentation, but it did not specify how to disposition informal information. This step required a review of vendor documentation by engineering to ensure design requirements are met. Procedure AP 05-013, step 6.6, specified incorporating changes to vendor documents that originate with Wolf Creek, but it did not specify that the vendor must be contacted for changes that Wolf Creek has not evaluated. Procedure AP 05-002, "Dispositions and Change Packages," Revision 8, specified how Wolf Creek prepares, documents, and implements modifications to plant equipment and design documents. Procedure AP 05-002, step 6.4.5, required that the data be obtained from the vendor and placed in the modification package supporting the plant change. Procedure AP 05-002, step 6.4.6.6, did not allow informal communications to form the basis for a modification. Telephone calls are defined as informal communication per Procedure AP 05-005. The inspectors found no documentation to show validation of the verbal data provided by the vendor. This modification was a corrective action to VIO 05000482/2009002-07 (EA-09-110). This notice of violation will remain open until full compliance has been restored. Wolf Creek subsequently consulted with Westinghouse to confirm the acceptability of the increased flow rate, and requested a formal calculation. This issue is captured in Condition Report 22824.

Analysis.

The inspectors found that the failure to follow procedure for the modification was a performance deficiency. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC's regulatory function, and the finding was not the result of any willful violation of NRC requirements or Wolf Creek procedures. The inspectors determined that this finding was more than minor because this issue aligned with Inspection Manual Chapter 0612, Appendix E, example 2.f, in that the modification relied on verbal statements to raise the allowable flow through the heat exchanger. This is a significant deficiency in the modification package. The inspectors determined this finding was associated with the design control attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609.04 and determined that the finding was of very low safety significance because assuming worst case degradation, the finding would not result in exceeding the technical specification limit for identified reactor coolant system leakage and would not have likely affected other mitigation systems resulting in a total loss of their safety function because seal injection was available. This finding has a crosscutting aspect in the area of human performance associated with work practices in that management was unsuccessful in communicating expectations on procedure use and adherence in engineering H.4.b].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control," requires, in part, that the licensee establish measures for the identification and control of design interfaces and for coordination among participating design organizations. These measures shall include the establishment of procedures among participating design organizations for the review, approval, release, distribution, and revision of documents involving design interfaces. It also requires, in part, that design changes shall be subject to design control measures commensurate with those applied to the original design.

Procedures AP 05-005 and AP 05-002 implement this requirement by requiring formal vendor data required for modifications to be incorporated into modifications. Contrary to the above, from August 13, 2009, to December 31, 2009, Wolf Creek failed to obtain vendor design data for configuration change Package 013096 in accordance with Procedures AP 05-005 and AP 05-002. Because the finding is of very low safety significance and has been entered into the corrective action program as Condition Report 22824, this violation is being treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-10, "Failure to Obtain Vendor Data Necessary for Plant Modification."

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:

• October 23, 2009, Emergency diesel generator A run after replacement of speed switch

• October 23, 2009, Instrumentation and control testing of emergency diesel generator A instrument power supply

• November 6, 2009, Essential service water train B pump and motor replacement

• November 2, 2009, Motor-operated valve MOV 8811A after actuator and internals replacement The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following (as applicable):

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

• Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate The inspectors evaluated the activities against the technical specifications, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with postmaintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of four postmaintenance testing inspection samples as defined in Inspection Procedure IP 71111.19-05.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Wolf Creek refueling outage, conducted from October 10 to November 17 2009, to confirm that licensee personnel had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense in depth. During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

• Configuration management, including maintenance of defense in depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.

• Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

• Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error.

• Status and configuration of electrical systems to ensure that technical specifications and outage safety-plan requirements were met, and controls over switchyard activities.

• Monitoring of decay heat removal processes, systems, and components.

• Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

• Reactor water inventory controls, including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

• Controls over activities that could affect reactivity.

• Maintenance of secondary containment as required by the technical specifications.

• Refueling activities, including fuel handling and sipping to detect fuel assembly leakage.

• Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing.

• Licensee identification and resolution of problems related to refueling outage activities. Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of one refueling outage and other outage inspection sample as defined in Inspection Procedure IP 71111.20-05.

b. Findings

===.1

=

The inspectors identified a Green cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for failure to correct a previous violation for an inadequate vent path for the reactor vessel head.

Description.

NRC Inspection Report 05000482/2008004 documented a Green noncited violation of 10 CFR Part 50, Criterion III, "Design Control," associated with the formation of voids in the reactor vessel head during refueling outages. During Refueling Outage 17 on October 13, 2009, Wolf Creek depressurized the reactor and drained the reactor coolant system via the pressurizer to a level 374 inches above the bottom of the hot leg. Reactor coolant system pressure was established at atmospheric pressure, approximately 6-10 psig below the volume control tank pressure. These actions were performed in accordance with plant operating Procedure SYS BB-215, "RCS Drain Down with Fuel in Reactor." The operators completed Sections 6.1 and 6.2 of the procedure to vent the reactor vessel head to the pressurizer and purge the pressurizer with nitrogen. Control room operators subsequently initiated Condition Reports 20648 and 20633 to identify anomalous readings in pressurizer and reactor vessel level. The inspectors reviewed plant computer data from October 11 to 14, 2009, and confirmed that a void had formed in the reactor vessel head region following reactor coolant system depressurization. As the gas built up, it forced primary coolant out of the reactor vessel and into the pressurizer over many hours, causing the observed level changes.

Following the previous refueling outage, Wolf Creek Mode 5 Procedure GEN 00-009 had been changed to require reactor vessel level instrumentation system to be in service so that control room operators could observe any decrease in reactor vessel level. Based on plant computer data, the observed change of approximately 41 inches in pressurizer level equated to a maximum void size of 1100 gallons of primary coolant in the reactor vessel. Excluding the void, time to boil in the reactor coolant system was calculated to be 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> during outage planning.

Following the formation of a similar void in Refueling Outage 16, Wolf Creek initiated a root cause evaluation during under Condition Report 2008-001032. The void size during Refueling Outage 16 was 2600 gallons. Wolf Creek determined that the root cause was a loop seal or blockage in the piping. The root cause described boron precipitation as a possible source of the blockage. Corrective actions were subsequently planned for Refueling Outage 17. The slope of the vessel head piping was verified to be correct to ensure no loop seals was performed as a corrective action to prevent recurrence.

However, after the piping slope was verified and loop seals ruled out as a possible cause, no additional actions were taken to identify the cause of the inadequate vent. A corrective action to perform an internal inspection of the vessel head was not performed because Wolf Creek did not have tools to inspect around 90 bends in the piping. The inspectors determined that Wolf Creek failed to identify the cause of the inadequate vent path to relieve gases to the pressurizer, with the result that voiding would continue to be a concern in the next refueling outage.

When the NRC issued NCV 05000482/2008004-07 on November 7, 2008, for the reactor vessel head voiding during outages, corrective actions were tracked under Condition Report 2008-001032. The inspectors concluded that Wolf Creek has yet to correct the inadequate vent path, allowing void formation to continue to occur in the reactor vessel head. Without an adequate vent from the top of the reactor vessel head to the pressurizer, noncondensable gas voids will form, decreasing reactor coolant inventory and reducing the time to core boiling following a loss of shutdown cooling. The gas voids could grow to the top of the hot legs or until the driving head forces the void past the blockage and into the gas space of the pressurizer, causing the plant to inadvertently enter mid-loop operations. An adequate vent path is necessary to control reactor coolant level. Wolf Creek has initiated a second root cause under Condition Report 22501.

Analysis.

The inspectors determined that failure to provide an adequate vessel head vent path to prevent gas accumulation in the reactor vessel during depressurized plant operations was a performance deficiency. The inspectors determined that this finding was associated with the design control attribute of the Initiating Events Cornerstone. Specifically, the voiding reduces time to boil and impacted the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the significance of this finding using Inspection Manual Chapter 0609, Appendix G, 1, "Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs." The inspectors determined that Checklist 3 was applicable because the unit was in cold shutdown with the refueling cavity level less than 23 feet. Based upon Appendix G, Attachment 1, Checklist 3, Phase 2, analysis was not needed to characterize the risk significance of this finding because the level of loss was less than two feet, did not occur during reduced inventory, and appropriate action was taken regarding the level deviation. The finding was determined to be of very low safety significance based upon the demonstrated availability of mitigation systems and the reactor coolant system cavity inventory. The inspectors determined the cause of the finding had a problem identification and resolution aspect in the corrective action program. Specifically, Wolf Creek's corrective actions were not successful to address the vent path blockage in a timely manner P.1(d).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that the design basis is correctly translated into specifications, drawings, and procedures. The design basis of the reactor vessel head vent is to allow noncondensable gases to escape to the pressurizer during shutdown conditions. Contrary to the above, from December 2, 2003, to December 31, 2009, Wolf Creek failed to ensure the design basis of the reactor vessel head vent was correctly translated into specifications, drawings, and procedures. Specifically, Wolf Creek designed and installed a reactor vessel head permanent vent piping modification which failed to vent noncondensable gases to the pressurizer during shutdown operations. This resulted in the formation of voids in the reactor vessel head while the plant was shutdown and depressurized in successive refueling outages. This issue and the corrective actions are being tracked by the licensee in Condition Reports 22501, 20648, 20568, and 20633. Due to the licensee's failure to restore compliance from previous NCV 05000482/2008004-07 within a reasonable time after the violation was identified, this violation is being cited as a Notice of Violation consistent with Section VI.A of the Enforcement Policy: VIO 05000482/2009005-11, "Failure to Correct Vessel Head Vent Path" (EA-10-020).

===.2

=

The inspectors identified a Green noncited violation of Technical Specification 5.4.1.a for failure to properly implement Procedure AP 14A-003, "Scaffold Construction and Use," when scaffolding was erected against operable safety-related equipment.

Description.

On October 15, 2009, the inspectors identified scaffolding in contact with component cooling water piping inside containment. The piping was the containment loop which did not have any required cooling loads, but was part of an operating component cooling water train that was cooling the core. At the time, reactor coolant system level was below the vessel flange. The tag on the scaffold explicitly stated that it was not seismically qualified. The inspectors discussed the issue with the shift manager who immediately had the scaffold moved. Both steam generators were inoperable and both trains of residual heat removal were required to be operable. The inspectors reviewed the bases for Technical Specification 3.4.7, "RCS Loops - Mode 5, Loops Filled," which required an operable heat sink path from residual heat removal to component cooling water to essential service water. Procedure AP 14A-003, "Scaffold Construction and Use," step 6.4.15, required scaffolding to be two inches away from equipment. Attachment F of this procedure specifies the requirements for seismically qualified scaffolds. The scaffold form stated that the scaffolding was required to be removed prior to Mode 4, which was incorrect because it allowed nonseismically qualified scaffold to be installed in the zone of influence of operable equipment since seismic qualification is still required for equipment required to be operable in Modes 5 and 6. This issue was entered into the corrective action program as Condition Report 22464.

Analysis.

The construction of an unqualified scaffold against operable component cooling water piping was a performance deficiency. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC's regulatory function, and the finding was not the result of any willful violation of NRC requirements or Wolf Creek procedures. The inspectors determined that this finding was more than minor because it is associated with the equipment performance attribute for the Mitigating Systems Cornerstone, and it affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, this issue relates to the availability and reliability examples of the equipment performance attribute because a latent failure mechanism was not evaluated. The inspectors evaluated the significance of this finding using Inspection Manual Chapter 0609, Appendix G, Attachment 1, "Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs." The inspectors determined that Checklist 3 was applicable because the unit was in cold shutdown with the refueling cavity level less than 23 feet. Using Appendix G, Attachment 1, Checklist 3, Phase 2 analysis was not needed and the finding was of very low safety significance (Green) because the licensee was able to demonstrate that the seismically unqualified scaffolding would not have resulted in a loss of safety function. The inspectors determined the cause of the finding had a human performance aspect in the area of resources. Specifically, Procedure AP 14A-003 was inadequate because it had conflicting guidance that allowed seismically unqualified scaffolds in Modes 5 and 6 H.2.c].

Enforcement.

Technical Specification 5.4.1.a requires that procedures be established, implemented and maintained as recommended in Regulatory Guide 1.33, Appendix A. Section 9.a of Appendix A, requires, in part, that maintenance affecting safety-related equipment be accomplished in accordance with procedures. Procedure AP 14A-003 "Scaffold Construction and Use," Revision 16, step 6.4.15 required two inches of clearance from safety-related structures. Contrary to the above, from October 14 to 15, 2009, the licensee did not provide two inches of clearance between scaffolding and safety-related structures. Specifically, component cooling water Train B was in contact with a seismically unqualified scaffold while component cooling water was required to be operable. Because the finding is of very low safety significance and has been entered into the corrective action program as Condition Report 22464, this violation is being treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-12, "Unevaluated Scaffold Against Component Cooling Water Piping."

1R22 Surveillance Testing

a. Inspection Scope

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

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• October 28, 2009, MOV 8811A as-found inservice surveillance test

• August 10, 2009, STS IC-250B, Channel operational test containment atmosphere and reactor coolant system leak rate radiation Monitor GT RE-0031

• November 5, 2009, STS PE-139, Local leak rate test of Penetration 39, BB HV-351C

• September 17, 2009, Train A auxiliary feedwater inservice testing of Valves ALV0002 and ALV0009

• November 3, 2009, Essential service water Train B leak test of underground pipe

• September 28, 2009, Emergency Diesel Generator A, 24-hour endurance run

• October 15, 2009, Emergency Diesel Panel KJ-122/123 safety to nonsafety fuse inspections Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of seven surveillance testing inspection samples as defined in Inspection Procedure IP 71111.22-05.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational and Public Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

This area was inspected to assess licensee personnel's performance in implementing physical and administrative controls for airborne radioactivity areas, radiation areas, high radiation areas, and worker adherence to these controls. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensee's procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspectors performed independent radiation dose rate measurements and reviewed the following items:

• Performance indicator events and associated documentation packages reported by the licensee in the Occupational Radiation Safety Cornerstone

• Controls (surveys, posting, and barricades) of radiation, high radiation, or airborne radioactivity areas

• Radiation work permits, procedures, engineering controls, and air sampler locations

• Conformity of electronic personal dosimeter alarm set points with survey indications and plant policy; workers' knowledge of required actions when their electronic personnel dosimeter noticeably malfunctions or alarms

• Barrier integrity and performance of engineering controls in airborne radioactivity areas

• Physical and programmatic controls for highly activated or contaminated materials (nonfuel) stored within spent fuel and other storage pools

• Self-assessments, audits, licensee event reports, and special reports related to the access control program since the last inspection

• Corrective action documents related to access controls

• Licensee actions in cases of repetitive deficiencies or significant individual deficiencies

• Radiation work permit briefings and worker instructions

• Adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination control during job performance

• Dosimetry placement in high radiation work areas with significant dose rate gradients

• Changes in licensee procedural controls of high dose rate - high radiation areas and very high radiation areas

• Controls for special areas that have the potential to become very high radiation areas during certain plant operations

• Posting and locking of entrances to all accessible high dose rate - high radiation areas and very high radiation areas

• Radiation worker and radiation protection technician performance with respect to radiation protection work requirements Either because the conditions did not exist or an event had not occurred, no opportunities were available to review the following items:

• Adequacy of the licensee's internal dose assessment for any actual internal exposure greater than 50 millirem committed effective dose equivalent These activities constitute completion of 21 of the required 21 samples as defined in Inspection Procedure IP 71121.01-05.

b. Findings

===.1

=

The inspector identified a Green noncited violation of Technical Specification 5.7.2.a.1 for failure to maintain administrative control of door and gate keys to high radiation areas with dose rates greater than 1 rem per hour but less than 500 rads per hour (referred to as locked high radiation areas).

Description.

During a review of the licensee's program for administrative control of keys to doors and gates to locked high radiation areas and very high radiation areas, the inspector found that the health physics department had a master key to locked high radiation areas. This key was not controlled in accordance with licensee Procedure AP 25A-200, "Access to Locked High or Very High Radiation Areas," Revision 20, which stated that site security was responsible for issuing locked high radiation area and very high radiation area keys. In accordance with technical specifications, health physics management designated the site security department to administratively (and procedurally) control the keys. Although site security was effectively meeting the procedure requirement for issuing all other locked and very high radiation area keys, site security was unaware that the health physics department had the only master key to locked high radiation areas at the site. By procedure, site security administratively controlled the other keys (to locked and very high radiation areas) by maintaining an inventory of them, performing physical inventories of the keys each shift, and labeling the keys. None of these administrative controls were implemented for the master key in the health physics department. The licensee immediately documented the deficiency in a condition report and implemented temporary administrative controls until a permanent disposition for the master key had been identified.

Analysis.

Failure to maintain administrative control of the master key to locked high radiation areas was a performance deficiency. This finding is greater than minor because if left uncorrected the finding has the potential to lead to a more significant safety concern in that an individual could receive unanticipated radiation dose by gaining access a locked high radiation area without the proper controls and briefing. This finding was evaluated using Inspection Manual Chapter 0609, "Significance Determination Process," Appendix C, "Occupational Radiation Safety Significance Determination Process," and was determined to be of very low safety significance because it did not involve:

(1) an as low as is reasonably achievable (ALARA) planning or work control issue,

(2) an overexposure,

(3) a substantial potential for overexposure, or

(4) an impaired ability to assess dose. Additionally, the violation has a crosscutting aspect in the area of human performance associated with the work practices component because the lack of peer and self-checking resulted in inadequate control of keys to locked high radiation areas H.4(a).

Enforcement.

Technical Specification 5.7.2.a.1 requires, in part, that each entryway to a high radiation area with dose rates greater than 1.0 rem per hour but less than 500 rads per hour shall be provided with a locked or continuously guarded door or gate that prevents unauthorized entry and all keys shall be maintained under the administrative control of the shift manager/control room supervisor, health physics supervision, or his/her designee. Contrary to the above, as of October 21, 2009, the licensee failed to maintain administrative control of a master key to high radiation areas with dose rates in excess of 1.0 rem per hour but less than 500 rads per hour. Because this violation was of very low safety significance and has been entered into the licensee's corrective action program as Condition Report 20973, it is being treated as a noncited violation consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-13, "Failure to Maintain Administrative Control of Keys to Locked High Radiation Areas." 2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

The inspectors assessed licensee personnel's performance with respect to maintaining individual and collective radiation exposures as low as is reasonably achievable. The inspectors used the requirements in 10 CFR Part 20 and the licensee's procedures required by technical specifications as criteria for determining compliance. The inspectors interviewed licensee personnel and reviewed the following:

• Five outage or on-line maintenance work activities scheduled during the inspection period and associated work activity exposure estimates which were likely to result in the highest personnel collective exposures

• Site-specific ALARA procedures

• ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements

• Interfaces between operations, radiation protection, maintenance, maintenance planning, scheduling and engineering groups

• Shielding requests and dose/benefit analyses

• Dose rate reduction activities in work planning

• Use of engineering controls to achieve dose reductions and dose reduction benefits afforded by shielding

• Workers' use of the low dose waiting areas

• First-line job supervisors' contribution to ensuring work activities are conducted in a dose efficient manner

• Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas

• Self-assessments, audits, and special reports related to the ALARA program since the last inspection

• Corrective action documents related to the ALARA program and follow-up activities, such as initial problem identification, characterization, and tracking Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of 6 of the required 15 samples and 6 of the optional samples as defined in Inspection Procedure IP 71121.02-05.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the 3rd Quarter 2009 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, "Performance Indicator Program." This review was performed as part of the inspectors' normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings of significance were identified.

.2 Mitigating Systems Performance Index - Emergency ac Power Systema. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Emergency ac Power System performance indicator data for the period from the 4 th quarter 2008 through the 3 rd quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Revision 6 of the Nuclear Energy Institute (NEI) Document 99-02, "Regulatory Assessment Performance Indicator Guideline," were used. The inspectors reviewed the licensee's operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of October 1, 2008, through September 30, 2009, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report. This inspection constitutes one mitigating systems performance index - emergency ac power system sample as defined by Inspection Procedure IP 71151.

b. Findings

No findings of significance were identified.

.3 Mitigating Systems Performance Index - High Pressure Injection Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - High Pressure Injection Systems performance indicator data for the period from the 4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Revision 6 of the NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 1, 2008, through September 30, 2009, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report. This inspection constitutes one mitigating systems performance index - high pressure injection system sample as defined by Inspection Procedure IP 71151.

b. Findings

No findings of significance were identified.

.4 Mitigating Systems Performance Index - Auxiliary Feedwater System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Auxiliary Feedwater System performance indicator data for the period from the 4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Revision 6 of the NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, event reports, mitigating systems performance index derivation reports, and NRC integrated inspection reports for the period of October 1, 2008, through September 30, 2009, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

This inspection constitutes one mitigating systems performance index - auxiliary feedwater sample as defined by Inspection Procedure IP 71151.

b. Findings

No findings of significance were identified.

.5 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Residual Heat Removal System performance indicator data for the period from the 4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Revision 6 of the NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 1, 2008, through September 30, 2009, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report. This inspection constitutes one Mitigating Systems Performance Index - Residual Heat Removal System sample as defined by Inspection Procedure IP 71151.

b. Findings

No findings of significance were identified.

.6 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Cooling Water Systems performance indicator data for the period from the 4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Revision 6 of the NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 1, 2008, to September 30, 2009, to validate the 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 licensee's issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report. This inspection constitutes one mitigating systems performance index - cooling water system sample as defined by Inspection Procedure IP 71151.

b. Findings

No findings of significance were identified.

.7 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences performance indicator for the period from the 4th quarter 2008 through 3rd quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, was used. The inspectors reviewed the licensee's assessment of the performance indicator for occupational radiation safety to determine if indicator related data was adequately assessed and reported. To assess the adequacy of the licensee's performance indicator data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review, and the results of those reviews. The inspectors independently reviewed electronic dosimetry dose rate and accumulated dose alarm and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very high radiation area entrances to determine the adequacy of the controls in place for these areas.

These activities constitute completion of the occupational radiological occurrences sample as defined in Inspection Procedure IP 71151-05.

b. Findings

No findings of significance were identified.

.8 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual Radiological Effluent Occurrences performance indicator for the period from the 4th quarter 2008 through 3rd quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, was used. The inspectors reviewed the licensee's issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose.

These activities constitute completion of the radiological effluent technical specifications/offsite dose calculation manual radiological effluent occurrences sample as defined in Inspection Procedure IP 71151-05.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

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

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included: the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensee's corrective action program because of the inspectors' observations are included in the attached list of documents reviewed.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by inspection procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings of significance were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for followup, the inspectors performed a daily screening of items entered into the licensee's corrective action program. The inspectors accomplished this through review of the station's daily corrective action documents. The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings of significance were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensee's corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on repetitive equipment issues, but also considered the results of daily corrective action item screening discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human performance results. The inspectors nominally considered the 6-month period of June 30 through December 31, 2009, although some examples expanded beyond those dates where the scope of the trend warranted. The inspectors also included issues documented outside the normal corrective action program in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and maintenance rule assessments. The inspectors compared and contrasted their results with the results contained in the licensee's corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensee's trending reports were reviewed for adequacy. These activities constitute completion of one single semi-annual trend inspection sample as defined in Inspection Procedure IP 71152-05.

b. Findings

No findings of significance were identified.

.4 Selected Issue Follow-up Inspection

a. Inspection Scope

The inspectors selected two issues for follow-up inspection per Inspection Procedure IP 71152. During a review of items entered in the licensee's corrective action program, the inspectors recognized a corrective action item documenting a problem with extraction steam on June 23, 2009, that caused an increase in reactivity. The inspectors reviewed corrective actions and new procedure changes for level control of high pressure feedwater heaters. The inspectors also reviewed several condition reports and interviewed personnel pertaining to the intermediate range nuclear instrument NI-36. The deficiencies associated with NI-36 constituted one in-depth review of an operator work-around. These activities constitute completion of two in-depth problem identification and resolution samples as defined in Inspection Procedure IP 71152-05.

b. Findings

Introduction.

On December 30, 2009, the inspectors identified a Green noncited violation of Technical Specification, Table 3.3.1-1, Function 18.a, when Wolf Creek restarted from on May 18, 2005.

Description.

On April 9, 2005, Wolf Creek shut down for Refueling Outage 14. The inspectors found no control room log entries stating that source range instrument NI-32 had to be manually energized. The inspectors reviewed a completed copy of STN IC-236, Revision 4, dated April 9, 2005, which stated that compensation voltage and current were found within tolerance and were left as-found. At the end of Refueling Outage 14, in Mode 3, NI-36 indication deviated from indication from intermediate range detector NI-35. During interviews with licensed operators, when shutdown banks were withdrawn, NI-36 went above 6 E-11 amps and cleared the P-6 interlock while the reactor was subcritical. Indication above 6E-11 normally means the reactor is critical. The source ranges' count rates and NI-35 also increased, but did not indicate criticality.

Troubleshooting was performed under Work Order 05-272906-000 was performed on May 16, 2005. Instrumentation and controls technicians disconnected, cleaned, and reconnected NI-36 cables. The NI-36 cables were then disconnected and reconnected two more times. Work Order 05-272906-000 was also used to perform STS IC-436, "Channel Calibration NIS Intermediate Range N-36," Revision 15, test the log current amplifier and indicator calibrations, Work Order 05-272906-000 was also used to perform STN IC-236, "Intermediate Range N36 Compensation Voltage Adjustment," Revision 4 to calibrate the compensating voltage power supply and test the loss of compensating voltage bistable relay driver. On May 17, 2005, during calibration of the compensating voltage, during step 8.2.4.1, the technicians noted that compensating voltage was not changing indication permanently, only temporarily. The as-found and as-left compensating voltage were satisfactory, but the compensating current as-found and as-left was at 1E-10amps which is one order of magnitude above the 3E-11amps acceptance criteria. The surveillance was closed stating "used only as troubleshooting tool only. No credit taken." The surveillance test routing sheet noted this as a technical specification failure. This was then used to generate Work Order 05-272906-000 which stated that there was a possible problem with the signal cable for NI-32 and the compensation cable for NI-36 and to rework the cables. The operators had to remove instrument fuses from the NI-36 instrument rack to cause the interlock to clear after the efforts below. During control rod pulls during preparations for criticality, the P-6 interlock came in with the reactor subcritical. Fuses had to later be pulled and re-inserted to clear the interlock after NI-36 was worked during this series of work orders. Using Work Order 05-272926-005, the technicians used STS IC-236 to successfully test the positive and negative 25 Vdc power supplies, the high voltage power supply, the "power above permissive P-6 bistable relay driver," and the reactor trip high level bistable relay driver. However, other than disconnecting cleaning, and reconnecting the connectors, no corrective maintenance was performed on cables. The cause of the failure was documented as "suspect loose connection". Wolf Creek concluded that after the above efforts, that NI-36 indication had been reduced sufficiently to declare it operable because it channel checked with NI-35 to within one decade. Reactor startup commenced on May 18, 2005, and concluded Refueling Outage 14. During a reactor shutdown for Refueling Outage 15 on October 7, 2006, intermediate range neutron Detector NI-36 did not decrease below 6E -11 amps and energize source range detector NI-32. Following NI-36's failure to decrease below the P-6 setpoint, reactor operators correctly transitioned to Procedure OFN SB-008, "Instrument Malfunctions" to manually energize source range detector NI-32. On October 7, 2006, Wolf Creek performed STN IC-236 under Work Order 05-274604-000. Detector NI-36 failed STN IC-236, "Intermediate Range N36 Compensation Voltage Adjustment", Revision 4, because the as-found detector current was outside of the tolerance range at 9E-11 amps (upper limit is 3E-11 amps) and could not be adjusted to within the tolerance. As-found compensating voltage was within the allowable range. Wolf Creek then replaced the jacks for the triaxial connector using Work Order 05-272987-000. Work Order 05-272987-000 stated that the connector was found "failed" but did not state what acceptance criteria it did not meet. Work Order 05-272987-000 stated that the cause of the failure was "suspect failed connector." Also, Work Order 05-272987-000 took measurements of the compensation voltage cable insulation resistance testing, but stated no acceptance criteria. Work Order 05-272987-000 the performed surveillance test STS IC-236, "Channel Operational Test Nuclear Instrumentation System Intermediate Range N-36 Protection Set II," Revision 17, which was followed by Work Order 06-289017-000 to perform STN IC-236. On October 17, 2006, STN IC-236 adjusted the compensating voltage to be more positive. The as-found adjustment of the detector current was less than 1E-11amps, which was outside the STN IC-236 acceptance criteria. The inspectors noted that the instrument drawer will not allow detector current to decrease below 1E-11 amps due to a designed idling current at 1E-11 amps. As-left current was 1E-11 amps. Later in the outage, control room operators requested that instrumentation and control workers adjust NI-36 because its output was not tracking with the other intermediate range detector, NI-35.

On November 9, 2006, STN IC-236 was performed again. During this test, compensation current was unable to be adjusted below 3E-11 amps. The as-found value was 7E-11 amps and the as-left value was 6E-11 amps. The 6E-11 amp current was outside the allowable limit, but the surveillance procedure was completed with a deficiency stating "no credit taken." The surveillance cover sheet said that NI-36 was reading within an order of magnitude of NI-35. The control room logs stated the same. Work Order 06-290208-000 was generated to replace the detector during the Refueling Outage 16. On March 17, 2008, Wolf Creek tripped from 100 percent power and NI-36 automatically energized source range detector NI-32. The inspectors checked plant computer data and found that the source range instrument energized at 5E-11 amps which is below the acceptance criteria of greater than 6 E-11amps (P-6 setpoint). The detector was subsequently replaced during Refueling Outage 16. The need to transition to Procedure EMG FR-S2, "Response to Loss of Core Shutdown," was not previously identified in a condition report, operator work around, or operator burden. The inspectors found no other evaluation of the detector's behavior before Wolf Creek ascended to Mode 2 in Refueling Outages 14 and 15. The inspectors found that the connector cleaning in Refueling Outage 14 and the jack replacement in Refueling Outage 15 were not likely to correct the problem found in STN IC-236. The inspectors concluded that the STN IC-236 surveillances in Refueling Outage 14 and Refueling Outage 15 had not met the acceptance criteria and that startup should not have continued until the nuclear instrument issue was resolved. Wolf Creek did not identify the issue as a technical specification violation. Although work orders were planned in Refueling Outage 14 to replace NI-36, all were closed without action. The inspectors found that NI-36 was conditioned through "troubleshooting" until it could pass its one decade channel check. Other testing performed by Wolf Creek only impacted the instrument drawer in the control room, while the problem was related to the detector itself. Condition Report 2006-003187 found that the problems with compensating voltage could not be determined, but concluded that it was not necessary for operability because the system had no risk significance. The inspectors determined that the compensation current is critical to the operation of the detectors because the design of the compensated ion chamber is to allow the instrument drawer to sum currents in opposing directions to discriminate neutrons from gamma. The condition report also identified that the P-6 interlock may not work correctly, but no action was taken. The inspectors reviewed Wolf Creek Technical Specification 3.3.1, Function 18.a, "Intermediate Range Flux, P-6 [interlock]," and its bases statement. The bases state that Function 18.a ensures that, on decreasing power, the P-6 interlock automatically energizes nuclear instrumentation source range detectors and enables the source range neutron flux reactor trip. During reactor trip, the function is required as reactor power decreases to energize the source range detectors and the source range reactor trips. The inspectors found that Wolf Creek's bases are consistent with the NUREG-1431, "Standard Technical Specifications Westinghouse Plants," Revision 3.0.

Analysis.

The inspectors determined that the failure to ensure that the P-6 interlock was operable per the technical specification as defined in the bases was a performance deficiency. The finding was more than minor because it was associated with the configuration control (reactivity control) attribute of the Barrier Integrity Cornerstone, and it affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the significance of this finding under the Mitigating Systems Cornerstone using Phase 1 of Inspection Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," and determined that the finding screened to Green because the P-6 interlock only affected the fuel barrier. This finding was not assigned a crosscutting aspect because the cause was not representative of current performance.

Enforcement.

Wolf Creek Technical Specification, Table 3.3.1-1, Function 18.a, requires, in part, that when intermediate range instrument measured neutron flux decreases below the allowable value of greater than or equal to 6 E-11 amps that the source range instruments be energized and enable the source range reactor trip signal. Technical Specification, Table 3.3.1-1, Function 4, requires the intermediate range detectors to be operable at low power in Modes 1 and 2. These functions are required on reactor trip. Contrary to the above, from May 17, 2005, to March 17, 2008, intermediate range detector NI-36 was inoperable because its output did not decrease below the P-6 setpoint when the reactor tripped and failed to energize source range instrument NI-32 and the source range reactor trip. Because this violation was determined to be of very low safety significance and was placed in the corrective action program as Condition Report 00022450, this violation is being treated as a noncited violation in accordance with Section VI.A.1 of the Enforcement Policy: NCV 05000482/2009005-14, "Failure to Identify Inoperable P-6 Interlock and Intermediate Range Detector."

4OA3 Event Follow-up

.1 Response to Notice of Unusual Event

On October 22, 2009, Emergency Diesel Generator B was out of service for planned maintenance. At 12:06 p.m., the Wolf Creek control room received trouble annunciators for Emergency Diesel Generator A. The speed sensor failed high which would cause any diesel start to fail. This stopped the jacket water keep warm pump, and prevented air start system solenoids from starting the engine. Since the engine was in standby, low lube oil pressure also would have prevented the engine from starting. Wolf Creek initiated troubleshooting and repair. At 5:39 p.m., Wolf Creek declared an Unusual Event under Emergency Action Level (EAL) 6/AC5 for loss of both diesels with the reactor defueled. At 5:45 p.m., Wolf Creek made notification to state and local governments of the Notice of Unusual Event. At 7:14 p.m., Wolf Creek notified the NRC Operations Officer that the power supply had excessive voltage ripple which caused the speed sensor's failure. The speed switch and its power supply were replaced. The inspectors observed control room activities, repair activities, and post-maintenance testing of repairs. On October 23, 2009, at 7:38 a.m., Emergency Diesel Generator A was restored to operable status and the unusual event was terminated.

b. Findings

One violation of very low safety significance (Green) is described in Section

4OA7 of this report.

.2 Licensee Event Report Review

a. Inspection Scope

The inspectors reviewed potentially reportable events under Inspection Procedure IP 71153. Inspectors also utilized NUREG 1022, "Event Reporting Guidelines 10 CFR 50.72 and 50.73," Revision 2.

b. Findings

Introduction.

The inspectors identified a Severity Level IV noncited violation of 10 CFR 50.73, in which the licensee failed to submit licensee event reports within 60 days following discovery of events or conditions meeting the reportability criteria.

Description.

The licensee submitted Licensee Event Report LER 2009-009-00 under 10 CFR 50.73(a)(2)(i)(B) for an operation prohibited by technical specifications. The inspectors determined this event report was not submitted within the 60 days allowed by 10 CFR 50.73. The inspectors identified that other reporting requirements of 50.73 also applied but were not included in the licensee event report. In the event on August 22, 2009, Wolf Creek disabled both trains of the P-4 interlock for planned maintenance. Specifically, the feedwater isolation signal that is generated by P-4 (reactor trip coincident with low Tave) was taken out of service for control rod drive motor-generator set testing. This allowed reactor trip breaker cycling without isolation of main feedwater. The P-4 interlock was required by Technical Specification 3.3.2 function 8.a. This function is discussed in USAR Section 7.3.8, "NSSS Engineered Safety Feature Actuation System." which describes the function of a main feedwater isolation as to prevent or mitigate the effect of an excessive cooldown. Wolf Creek technical specification Bases also state that one or more functions may backup other engineered safety feature actuation signal functions credited in Chapter 15 of the USAR. Licensee Event Report 2009-009-00 reported a condition prohibited by technical specifications under a(2)(i)(B) and correctly described that the P-4 interlock was not credited in accident analysis. The licensee did not report the event under reporting criteria 50.73(a)(2)(v). The engineered safety features actuation signal system has other signals that cause feedwater isolations that are used in Chapter 15 of the USAR.

The inspectors consulted NUREG 1022, "Event Reporting Guidelines 10 CFR 50.72 and 50.73," Revision 2. NUREG 1022, Section 3.2.7, reportability under 50.73(a)(2)(v), specified that inoperable systems required by the technical specifications are to be reported, even if there are other diverse, operable means of accomplishing the safety function. The inspectors found that Wolf Creek was not correct in concluding that the 50.73(a)(2)(v)(A) through (D) only applied to the accident analysis contained in Chapter 15 of the USAR. The inspectors consulted with the NRC Office of Nuclear Reactor Regulation, who agreed with the inspectors' application of the rule and NUREG 1022. The untimely licensee event report was entered into the corrective action program as Condition Report 22781.

Analysis.

The failure to submit a timely and complete licensee event report was a performance deficiency. The inspectors reviewed this issue in accordance with Inspection Manual Chapter 0612 and the NRC Enforcement Manual. Through this review, the inspectors determined that traditional enforcement was applicable to this issue because the NRC's regulatory ability was affected. Specifically, the NRC relies on the licensee to identify and report conditions or events meeting the criteria specified in regulations in order to perform its regulatory function, and when this is not done, the regulatory function is impacted. The inspectors determined that this finding was not suitable for evaluation using the significance determination process, and as such, was evaluated in accordance with the NRC Enforcement Policy. The finding was reviewed by NRC management, and because the violation was determined to be of very low safety significance, was not repetitive or willful, and was entered into the corrective action program, this violation is being treated as a Severity Level IV noncited violation consistent with the NRC Enforcement Policy. This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program in that the licensee failed to appropriately and thoroughly evaluate for reportability aspects all factors and time frames associated with the inoperability of the engineered safety features actuation system P.1(c).

Enforcement.

Title 10 CFR 50.73(a)(1) requires, in part, that licensees shall submit a licensee event report for any event of the type described in this paragraph within 60 days after the discovery of the event. Title 10 CFR 50.73(a)(2)(v) requires, in part, that events or conditions that could have prevented the fulfillment of the safety function of structures or systems that are needed to shutdown the reactor and maintain it in a safe shutdown condition, remove residual heat, control the release of radioactive material, or mitigate the consequences of an accident. Contrary to the above, on October 23, 2009, Wolf Creek failed to submit a licensee event report within 60 days for removing the P-4 interlock from service, and failed to identify that the condition could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident. In accordance with the NRC's Enforcement Policy, the finding was reviewed by NRC management and because the violation was of very low safety significance, was not repetitive or willful, and was entered into the corrective action program, this violation is being treated as a Severity Level IV noncited violation, consistent with the NRC Enforcement Policy: NCV 05000482/2009005-15, "Failure to Report a Condition that Could Have Prevented Fulfillment of a Safety Function."

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors performed observations of security force personnel and activities to ensure that the activities were consistent with Wolf Creek security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off-normal plant working hours. These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

b. Findings

No findings of significance were identified.

.2 Temporary Instruction 2515-172, "Reactor Coolant System Dissimilar Metal Butt Welds"

a. Inspection Scope

Portions of Temporary Instruction 2515/172, "Reactor Coolant System Dissimilar Metal Butt Welds," were performed at Wolf Creek during Refueling Outage 17. Specific documents reviewed during this inspection are listed in the attachment. This unit has the following dissimilar metal butt welds.

COMPONENT ID DESCRIPTIONMRP-139 CATEGORYBASELINE EXAM COMMENTRV-301-121-A Loop 1 Outlet Nozzle to Safe-end weld D April 2005 RF14 Next exam: October 2009 RF17 RV-301-121-B Loop 2 Outlet Nozzle to Safe-end weld D April 2005 RF14 Next exam: October 2009 RF17 RV-301-121-C Loop 3 Outlet Nozzle to Safe-end weld D April 2005 RF14 Next exam: October 2009 RF17 RV-301-121-D Loop 4 Outlet Nozzle to Safe-end weld D April 2005 RF14 Next exam: October 2009 RF17 RV-302-121-A Loop 1 Inlet Nozzle to Safe-end weld E April 2005 RF14 Next exam: April 2011 RF18 RV-302-121-B Loop 2 Inlet Nozzle to Safe-E April 2005 Next exam:

COMPONENT ID DESCRIPTIONMRP-139 CATEGORYBASELINE EXAM COMMENTend weld RF14 April 2011 RF18 RV-302-121-C Loop 3 Inlet Nozzle to Safe-end weld E April 2005 RF14 Next exam: April 2011 RF18 RV-302-121-D Loop 4 Inlet Nozzle to Safe-end weld E April 2005 RF14 Next exam: April 2011 RF18 TBB03-1-W /

MW7090-WOL-DM Pressurizer surge nozzle to safe-end weld D / F October 2006 RF15 Note 1 TBB03-2-W / MW7089-WOL-DM Pressurizer spray nozzle to safe-end weld D / B October 2006 RF15 Note 1 TBB03-3-A-W / MW7086-WOL-DM Pressurizer safety nozzle A to safe-end weld D / B October 2006 RF15 Note 1 TBB03-3-B-W / MW7087-WOL-DM Pressurizer safety nozzle B to Safe-end weld D / B October 2006 RF15 Note 1 TBB03-3-C-W / MW7088-WOL-DM Pressurizer safety nozzle C to safe-end weld D / F October 2006 RF15 Note 1 TBB03-4-W / MW7085-WOL-DM Pressurizer relief nozzle to safe-end weld D / F October 2006 RF15 Note 1 Note 1: The pressurizer dissimilar metal butt-welds had full structural weld overlay applied in Refueling Outage 15. The first Component ID was the designation prior to overlay, the latter Component ID is the current weld designation (after overlay). Likewise, the first MRP-139 category was the designation prior to baseline exam and overlay, and the latter is the current designation (after overlay). Note that these locations are now examined in accordance with approved alternative of relief Request I3R-05.

03.01 Licensee's Implementation of the MRP-139 Baseline Inspections a. MRP-139 baseline inspections:

The inspectors reviewed records nondestructive examination activities associated with the licensee's hot leg inspection effort. The baseline inspections of the pressurizer dissimilar metal butt welds were completed during the spring 2008 Refueling Outage 16.

b. At the present time, the licensee is not planning to take any deviations from the baseline inspection requirements of MRP-139, and all other applicable dissimilar metal butt welds are scheduled in accordance with MRP-139 guidelines.

03.02 Volumetric Examinations a. The inspectors reviewed the ultrasonic examination records of the four unmitigated reactor hot leg nozzles and piping. The inspectors concluded that the ultrasonic examination for these welds was done in accordance with ASME Code,Section XI, Supplement VIII, Performance Demonstration Initiative requirements regarding personnel, procedures, and equipment qualifications. No relevant conditions were identified during these examinations.

b. The inspectors reviewed the nondestructive evaluations performed on the four reactor hot leg nozzles and piping. Inspection coverage met the requirements of MRP-139 and no relevant conditions were identified.

c. The certification records of examination personnel were reviewed for those personnel that performed the examinations of the inspected nozzles. All personnel records showed that they were qualified under the EPRI Performance Demonstration Initiative.

d. No deficiencies were identified during the nondestructive evaluations.

03.03 Weld Overlays.

The licensee performed all weld overlays during the previous outage (RF 15).

03.04 Mechanical Stress Improvement The licensee did not employ a mechanical stress improvement process this outage.

03.05 Inservice inspection program

a. Inspection Scope

The licensee's MRP-139 program is part of their Alloy 600 program and future inspections are in accordance with the MRP-139 requirements.

b. Findings

No findings of significance were identified.

.3 (Closed) Unresolved Item 05000482/2008010-04:

Operator Actions May Create the Potential for Secondary Fires

Introduction.

The inspectors identified a Green non-cited violation of License Condition 2.C.(5), "Fire Protection," for the failure to implement and maintain the approved fire protection program. Specifically, the licensee prescribed mitigating actions in response to certain fire scenarios that would result in a loss of circuit breaker coordination and could initiate secondary fires in plant locations outside of the initial fire area.

Description.

Procedure OFN KC-016, "Fire Response," Revision 19, specified operator actions to be taken in response to fires outside of the control room. This procedure provided the mitigating actions needed to maintain the reactor in hot standby in the event of various failures and spurious actuations. The inspectors identified the following 13 fire areas where the prescribed mitigating actions would remove electrical circuit protection (i.e., circuit breaker coordination) for the train affected by the fire and could initiate secondary fires in plant locations outside of the initial fire area:

• Fire Area A-8 Auxiliary Building - 2000' Elevation, General Area

• Fire Area A-11 Cable Chase (Room 1335)

• Fire Area A-16 Auxiliary Building - 2026' Elevation, General Area

• Fire Area A-17 South Electrical Penetration (Room 1409)

• Fire Area A-18 North Electrical Penetration (Room 1410)

• Fire Area C-18 North Vertical Cable Chase (Room 3419)

• Fire Area C-21 Lower Cable Spreading (Room 3501)

• Fire Area C-22 Upper Cable Spreading (Room 3801)

• Fire Area C-23 South Vertical Cable Chase (Room 3505)

• Fire Area C-24 North Electrical Chase (Room 3504)

• Fire Area C-30 South Vertical Cable Chase (Room 3617)

• Fire Area C-33 South Vertical Cable Chase (Room 3804)

• Fire Area RB Reactor Building (Containment)

For these fire areas, the procedure directed the operators to remove power to a power-operated relief valve if a fire caused the power-operated relief valve to spuriously open and operators could not close its associated block valve. Specifically, the procedure directed the operators to open circuit breakers on the associated 125 Vdc power supply. The inspectors noted that the failure of the block valve to close resulted from fire damage and not from a spurious operation of the valve. The licensee specified this action in order to close the power-operated relief valve and preclude the potential for spurious opening due to inter-cable faults (i.e., cable-to-cable hot shorts). However, the inspectors determined this action would also remove the control power used to operate 4160 Vac and 480 Vac circuit breakers. The removal of control power would prevent remote breaker operations and disable the circuit breaker protective trips for the train affected by the fire. Removing control power to the circuit breaker results in a loss of its ability to automatically isolate faults before severe damage occurs. As a result, fire-induced faults (shorts to ground) in non-essential power cables of the affected 4160 Vac and 480 Vac supplies may not clear until after tripping an upstream feeder breaker to the supplies, which would remove power from equipment that was assumed by the safe shutdown analysis to be unaffected. This action would also prevent breakers from automatically opening during an overload condition and could initiate secondary fires in plant locations outside of the initial fire area. The safe shutdown analysis assumed that a fire occurred in one fire area at any time. The inspectors determined that the mitigating actions taken in response to fires in the listed fire areas had the potential to initiate secondary fires in other plant locations, which would invalidate the safe shutdown analysis and could impact the ability to achieve and maintain safe shutdown.

Analysis.

Prescribing mitigating actions in response to certain fire scenarios that would result in a loss of circuit breaker coordination and could initiate secondary fires in plant locations outside of the initial fire area was a performance deficiency. The inspectors determined that this deficiency was more than minor because it was associated with the Protection Against External Factors attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The significance of this finding was evaluated using the Significance Determination Process in Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process," because it affected fire protection defense-in-depth strategies involving post-fire safe shutdown systems.

The inspectors associated the finding with the post-fire safe shutdown category since the performance deficiency would remove power from equipment that was assumed by the safe shutdown analysis to be unaffected and could initiate secondary fires in plant locations outside of the initial fire area. The inspectors assigned the finding a high degradation rating since the affected circuit breakers would not provide any fire protection benefit and would receive no fire protection credit. The inspectors performed a Phase 2 evaluation to determine an upper limit for the change in core damage frequency. The inspectors determined eight credible fire scenarios that could result in core damage under certain conservative assumptions. The pertinent parameters and results of these scenarios are summarized below. Attachment B provides a more detailed discussion of the Phase 2 evaluation.

Table 1. Phase 2 Evaluation Results Scenario Number Ignition Source Source Description (Fire Area)

Fire Ignition FrequencyHeat Release Rate Severity Factor Probability of Non-Suppression Probability of a Hot Short CCDP 1 RP-333 Relay Panel (A-16) 6.00E-5 200 kW 0.9 0.35 0.02 3.78E-7 2 RP-333 Relay Panel (A-16) 6.00E-5 650 kW 0.1 0.35 0.02 4.20E-8 3 SK194B Security Panel (A-16) 6.00E-5 200 kW 0.1 0.35 0.02 4.20E-8 4 NG01B 600V MCC (A-18) 6.00E-5 200 kW 0.1 0.44 0.02 5.28E-8 5 Transient Fire C-21 6.26E-6 70 kW 0.9 0.26 0.02 2.93E-8 6 Transient Fire C-21 6.26E-6 200 kW 0.1 0.26 0.02 3.26E-9 7 Transient Fire C-22 5.54E-6 70 kW 0.9 1.00 0.02 9.96E-8 8 Transient Fire C-22 5.54E-6 200 kW 0.1 1.00 0.02 1.11E-8 Total 6.58E-7 In each of these scenarios, the conditional core damage probability (CCDP) bounds the change in core damage frequency. The inspectors calculated the conditional core damage probability using the following equation:

Short Hot n Suppressio Non P x P x SF x FIF CCDP= where: F IF denotes the fire ignition frequency SF denotes the severity factor n Suppressio Non P denotes the non-suppression probability

Short Hot P denotes the probability of a hot short The sum of the conditional core damage probabilities for each of the fire scenarios bounded the total change in core damage frequency associated with this performance deficiency. Since the change in core damage frequency exceeded1E-7, the inspectors screened the finding for its potential risk contribution to a large early release frequency. In accordance with the guidance in NRC Inspection Manual Chapter 0609, Appendix H, the inspectors determined this finding did not involve a significant increase in the risk of a large early release of radiation because Wolf Creek has a large, dry containment and the accident sequences contributing to a change in the core damage frequency did not involve either a steam generator tube rupture or an intersystem loss of coolant accident. Since this bounding change in core damage frequency was less than 1E-6/year and the finding did not involve a significant increase in the risk of a large early release frequency, the inspectors determined this performance deficiency had very low risk significance (Green). This finding was not assigned a cross-cutting aspect because it existed more than two years and does not represent current performance. As a compensatory measure, the licensee implemented an hourly fire watch in the affected fire areas, with the exception of the reactor building, which is not readily accessible during power operations. For the reactor building, the licensee is monitoring the containment temperature as a compensatory measure.

Enforcement.

License Condition 2.C.(5) states, in part, that the licensee shall maintain in effect all provisions of the approved fire protection program as described in the Standardized Nuclear Unit Power Plant System (SNUPPS) Final Safety Analysis Report for the facility through Revision 17, the Wolf Creek Site Addendum through Revision 15, and as approved in the Safety Evaluation Report through Supplement 5. The Wolf Creek Updated Safety Analysis Report combined the SNUPPS Final Safety Analysis Report, Revision 17, and the Wolf Creek Site Addendum, Revision 15, into one document. Appendix 9.5B of the Updated Safety Analysis Report provides an area-by-area analysis of the power block that incorporated Drawing E-1F9905, "Fire Hazards Analysis," Revision 2, by reference. Drawing E-1F9905 states that the overall intent is to demonstrate that a single plant fire will not negatively affect the post-fire safe shutdown capability and that if a circuit damaged by a fire is protected by an individual overcurrent protection device, that device is assumed to function to clear the fault. Contrary to the above, prior to December 22, 2009, the licensee failed to implement and maintain in effect all provisions of the approved fire protection program. Specifically, the licensee prescribed mitigating actions in response to certain fire scenarios that would result in a loss of circuit breaker coordination (i.e., disable an overcurrent protection device from functioning to clear a fault) and could initiate secondary fires in plant locations outside of the initial fire area that negatively affect the post-fire safe shutdown capability. However, the plant's post-fire safe shutdown capability only evaluated damage resulting from a single fire.

The licensee entered this issue into their corrective action program as Performance Improvement Request 2008-005210. Because this violation was of very low safety significance and it was entered into the corrective action program, this violation is being treated as a non-cited violation, consistent with the NRC Enforcement Policy: NCV 05000482/2009005-16, Operator Actions Disable Circuit Breaker Coordination and Could Initiate Secondary Fires.

.4 (Closed) Unresolved Item 05000482/2008010-01:

Post-fire Safe Shutdown Inspection Did Not Identify Diagnostic Information During a triennial fire protection inspection in 2008, the inspectors identified an unresolved item concerning the availability of diagnostic instrumentation needed to respond to a loss of reactor coolant pump seal cooling during certain fire scenarios. The plant design uses reactor coolant pump seal injection and thermal barrier cooling to cool the reactor coolant pump seals. One method of seal cooling must be maintained during reactor coolant pump operation to prevent seal failure, which, in some cases, could lead to increased seal leakage beyond the capacity of the charging pump. The licensee identified that fire damage in four fire areas could isolate both methods of seal cooling. The inspectors identified that the licensee relied upon a decrease in pressurizer level to diagnose a loss of seal cooling. The inspectors determined the fire response procedure was inadequate since pressurizer level would not decrease until after seal failure occurred. Since the procedure required operators to recognize the loss of cooling and take response actions and the procedure did not identify adequate instrumentation to be used, the inspectors could not verify that it would remain free of fire damage for fires in these four fire areas. In response to the unresolved item, the licensee determined the instrumentation that would be available to diagnose a loss of seal cooling for fires in these four areas. The licensee determined that the thermal barrier flow switches and alarms would remain available for all four areas. The licensee also determined that seal injection flow and temperature would remain available for most, if not all, of the trains for each fire area. The inspectors reviewed the abnormal operating procedures used in the event of reactor coolant pump problems. Based on this review and the licensee's analysis of available instrumentation, the inspectors concluded that it was reasonable to believe that operators had sufficient instrumentation and guidance to promptly recognize, diagnose, and respond to a loss of reactor coolant pump seal cooling. The failure to establish written procedures adequately implementing the approved fire protection program was a performance deficiency and a violation of Technical Specification 5.4.1.d. The inspectors determined this performance deficiency was of minor safety significance since it was not similar to any example in Manual Chapter 0612, Appendix E, nor did it meet any of the minor questions in Manual Chapter 0612, Appendix B. This performance deficiency constitutes a violation of minor significance that is not subject to enforcement action in accordance with the NRC's Enforcement Policy.

The licensee implemented an hourly fire watch as an immediate compensatory measure and entered this issue into their corrective action program as Condition Report 2008-005171.

.5 (Closed) Licensee Event Report 05000482/2008006-00:

Entry Into Mode 4 Without An Operable Containment Spray System On July 3, 2008, Wolf Creek submitted LER 2008006 which described missed VT-2 weld inspections when modifying train B containment spray recirculation line in refueling outage 16. Wolf Creek stated that changes to shim the recirculation line inadvertently resulted in missing the VT-2 post-maintenance test. This resulted in ascending to Mode 4 without an operable containment spray system. Wolf Creek identified this issue on May 8, 2008, at 1:45am and entered Technical Specification 3.6.6 while in Mode 4. The VT-2 inspections were performed satisfactorily and Technical Specification 3.6.6 was exited at 3:13am on May 8, 2008. Enforcement aspects are discussed in Section 4OA7. This LER is closed.

.6 (Closed) Licensee Event Report 05000482/2008-08-00, -01, -02:

Potential for Residual Heat Removal Trains to be Inoperable during Mode Change.

All three revisions of this licensee event report were discussed and enforcement action was taken in NRC Inspection Report 05000482/2009006. This licensee event report is closed.

.7 (Closed) Unresolved Item 2008005-02:

Residual Heat Removal Suction Piping Saturation Temperature and Pressure.

This unresolved item was inspected and enforcement action was taken in NRC Inspection Report 05000482/2009006. This unresolved item is closed.

.8 (Closed) Licensee Event Report 05000482/2008-004-01:

Loss of Power Event When the Reactor was Defueled.

Licensee Event Report 05000482/2008-004-00 was closed in NRC Inspection Report 05000482/2008004 as a Green finding. In NRC Inspection Report 05000482/2009004, the inspectors identified a violation of 10 CFR 50.73 associated with this event report. Wolf Creek subsequently submitted revised Licensee Event Report 2008-004-01 in response to the Severity Level IV violation. The submittal of Licensee Event Report 05000482/2008-004-01 restores compliance with 10 CFR 50.73. This licensee event report is closed.

4OA6 Meetings

Exit Meeting Summary

On October 22, 2009, the radiation protection inspectors presented the inspection results to Mr. M. W. Sunseri and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On October 30, 2009, the in-service inspection inspectors debriefed the inspection results to Mr. M. W. Sunseri, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors acknowledged review of proprietary material during the inspection which had been or will be returned to the licensee.

On December 17 and 22, the fire protection inspectors conducted telephonic exit meetings and presented the results of the staff's closure of fire protection unresolved items. The inspectors presented the results to L. Ratzlaff, Manager Support Engineering, on December 17 and M.W. Sunseri, on December 22. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.

On January 14, 2010, the resident inspectors presented the inspection results of the resident inspections to Mr. M.W. Sunseri, and other members of the licensee's management staff. The licensee acknowledged the findings presented. The inspectors noted that while proprietary information was reviewed, none would be included in this report.

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as noncited violations.

.1 On October 22, 2009, at 12:06 p.m., the Wolf Creek control room received trouble annunciators for emergency diesel generator A.

Emergency diesel generator B was out of service for planned maintenance. 10 CFR 50.47(b)(4) requires that a standard emergency classification action level scheme be used by the licensee. Wolf Creek EAL 6, "Loss of Electrical Power/Assessment Capability," requires, in part, that when both emergency diesel generators are out of service for greater than 15 minutes, a Notice of Unusual Event be declared. Contrary to the above, on October 22, 2009, Wolf Creek did not declare a Notice of Unusual Event until 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after both emergency diesel generators were out of service. This issue is of very low safety significance (Green) because it is associated with failure to report a Notification of Unusual Event. Wolf Creek initiated Condition Report 21058 regarding the late declaration.

.2 On July 3, 2008, Wolf Creek submitted Licensee Event Report LER 2008006 which described missed VT-2 weld inspections when modifying train B containment spray recirculation line in Refueling Outage 16, requiring the train to be declared inoperable.

This issue has been entered in to the corrective action program as Condition Report 2008-2197. Technical Specification 3.0.4, states, in part, that when a limiting condition of operation is not met, that mode changes shall only be made: when actions to be entered permit continued operation for an unlimited period of time, after a risk assessment, or when an allowance is stated in the specification. Technical Specification Limiting Condition of Operation 3.6.6 requires, in part, two operable trains of containment spray in Modes 1 through 4. Contrary to the above, on May 8, 2008, Wolf Creek entered Mode 4 with only one operable containment spray system. This issue is of very low safety significance (Green) because there was no loss of function of the containment spray system.

1

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. D. Benham, Integrated Plant Scheduling

T. D. Card, Engineering

B. E. Dale, Manager Maintenance

T. M. Damashek, Superintendent, Operations Support

T. F. East, Manager, Emergency Planning

D. L. Fehr, Manager Information Systems

R. L. Gardner, Manager, Quality

S. E. Hedges, Vice President Oversight

D. M Hooper, Supervisor Licensing

J. K. Kent, Finance Management

W. R. Ketchum, Supervisor, Plant Safety Assessment

S. R. Koenig, Corrective Actions

W. T. Muilenburg, Licensing

P. J. Bedgood, Superintendent, Chemistry/Radiation Protection

C. L. Palmer, Major Modifications

J. M. Pankaskie, Supervisor, Design Engineering

E. M. Peterson, Ombudsman

D. Phelps, Owners Representative

B. Poteat, Piedmont

L. Ratzlaff, Manager, Support Engineering

E. A. Ray, Manager Chemistry/Health Physics

K. Scherich, Director Engineering

A. F. Stull, Vice President & Chief Administrative Officer

M. W. Sunseri, President and Chief Executive Officer

B. J. Vickery, Supply Chain

B. Walters, Supervisor, Security

M. J. Westman, Manager, Training

K. Frederickson, Licensing

J. Suter, Fire Protection

NRC Personnel

D. Loveless, Senior Reactor Analyst

Attachment 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000482/2009005-02 NCV Control of Transient Ignition Sources (Section 1R05)

05000482/2009005-03 NCV Failure to Identify Sources of Boron Leakage (Section 1R08)

05000482/2009005-04 NCV Failure to Incorporate Requirements of Regulatory Guide 1.182 into Daily Shutdown Risk Assessment (Section 1R13.1)

05000482/2009005-05 NCV Mode Change Under Technical Specification 3.0.4.b Without Required Risk Management Actions (Section 1R13.2)

05000482/2009005-06 NCV Failure to Follow Corrective Action Procedure (Section 1R13.3)

05000482/2009005-07 NCV Failure to Follow Procedure Results in Draining of Emergency Core Cooling System Pump Oil (Section 1R13.4)

05000482/2009005-08 NCV Inadequate Operability Evaluation of Essential Service Water Pumps (Section 1R15.1)

05000482/2009005-09 NCV Positive Reactivity Addition Prohibited by Technical Specifications while in Mode 2 (Section 1R15.2)

05000482/2009005-10 NCV Failure to Obtain Vendor Data Necessary for Plant Modification (Section 1R18)

05000482/2009005-12 NCV Unevaluated Scaffold Against Component Cooling Water Piping (Section 1R20)

05000482/2009005-13 NCV Failure to Maintain Administrative Control of Keys to Locked High Radiation Areas (Section 2SO1)

05000482/2009005-14 NCV Failure to Identify Inoperable P-6 Interlock and Intermediate Range Detector (Section 4OA2)

05000482/2009005-15

NCV Failure to Report a Condition that Could Have Prevented Fulfillment of a Safety Function (Section 4OA3)

05000482/2009005-16

NCV Operator Actions disable Circuit Breaker Coordination and Could Initiate Secondary Fires (Section 4OA5.1)

Attachment 1

Opened

05000482/2009005-01 VIO Failure to Correct Discolored Boric Acid Deposits (Section 1R05)

05000482/2009005-11 VIO Failure to Correct Vessel Head Vent Path (Section 1R20)

Discussed

05000482/2009002-07 VIO Failure to correct component cooling water valve closures (EA-09-110) (Section 1R18)

05000482/2009-005-00 LER Loss of both Diesel Generators with all fuel in the Spent Fuel Pool (Section 4OA3)

Closed

05000482/2008010-01 URI Post Fire Safe Shutdown Procedure Did Not Identify Diagnostic Information (Section 4OA5.4)

05000482/2008010-04 URI Operator Actions May Create the Potential for Secondary Fires (Section 4OA5.3)

05000482/2008-006-00 LER Entry Into Mode 4 Without An Operable Containment Spray System (4OA5.5)

05000482/2008-008-00

05000482/2008-008-01

05000482/2008-008-02 LER Potential for Residual Heat Removal Trains to be Inoperable during Mode Change (Section 4OA5.6)

05000482/2008005-02 URI Residual Heat Removal Suction Piping Saturation Temperature and Pressure (Section 4OA5.7)

05000482/2008-004-01 LER Loss of Power Event When the Reactor was Defueled (Section 4OA5.8)

Section 1RO1:

Adverse Weather Protection