IR 05000482/2012004

IR 05000482-12-004; Wolf Creek Nuclear Operating Corporation; 06/30/2012 - 09/28/2012; Wolf Creek Generating Station, Integrated Inspection Report

ML12314A296
Person / Time
Site:	Wolf Creek
Issue date:	11/09/2012
From:	O'Keefe N NRC/RGN-IV/DRP/RPB-B
To:	Matthew Sunseri Wolf Creek
O'Keefe N
References
IR-12-004
Download: ML12314A296 (91)

Text

November 9, 2012

SUBJECT:

WOLF CREEK GENERATING STATION - INTEGRATED INSPECTION REPORT 05000482/2012004

Dear Mr. Sunseri:

On September 28, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Wolf Creek Generating Plant. The enclosed inspection report documents the inspection results which were discussed on October 10, 2012, with Mr. R. Smith, Site Vice President, and other members of your staff.

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

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

Two NRC-identified and two self-revealing findings of very low safety significance (Green) were identified during this inspection. All of these findings were determined to involve violations of NRC requirements. Further, five licensee-identified violations which were determined to be of very low safety significance are listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Wolf Creek Generating Station.

If you disagree with a crosscutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at Wolf Creek.

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION IV

1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511

Sunseri, M.

- 2 -

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

Neil OKeefe, Chief Project Branch B Division of Reactor Projects

Docket No.: 05000482 License No: NPF-42

Enclosure:

Inspection Report 05000482/2012004 w/ Attachment 1: Supplemental Information

Attachment 2: Document Request

REGION IV==

Docket:

05000482 License:

NPF-042 Report:

05000482/2012004 Licensee:

Wolf Creek Nuclear Operating Corporation Facility:

Wolf Creek Generating Station Location:

1550 Oxen Lane NE, Burlington, Kansas Dates:

June 30 through September 28, 2012 Inspectors: C. Long, Senior Resident Inspector C. Peabody, Resident Inspector R. Kopriva, Senior Reactor Inspector J. Watkins, Reactor Inspector C. Speer, Reactor Inspector G. Guerra, Emergency Preparedness Inspector S. Hedger, Operations Engineer L. Ricketson, P.E., Senior Health Physicist N. Green, Ph.D., Health Physicist N. Makris, Project Engineer J. Laughlin, Emergency Preparedness Inspector Approved By:

Neil OKeefe, Chief, Project Branch B Division of Reactor Projects

- 5 -

Enclosure

SUMMARY OF FINDINGS

IR 05000482/2012004; 06/30/2012 - 09/28/2012, Wolf Creek Generation Station, Integrated

Resident and Regional Report; Operability Evaluations, Surveillance Testing, Radiological Hazard Assessment and Exposure Controls, Occupational ALARA Planning and Controls.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Four Green non-cited violations were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. The crosscutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross Cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

On August 30, 2012, inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for an operability evaluation that failed to adequately evaluate the operability of safety-related electrical equipment. On July 9, 2012, the inspectors identified that train B air conditioning unit SGK05B had a flow rate of 1,028 cfm below that of its design flow rate of 11,500 cfm during a flow rate surveillance test on June 8, 2011. Wolf Creek performed an operability evaluation when the inspectors questioned the test results.

The inspectors found that the evaluation contained non-conservative errors in cooling coil capacity specifications, incorrect assumptions for heat conducted into the switchgear rooms, unaccounted for latent and sensible heat sources, and a single failure that was not considered. Wolf Creek then expanded the operability evaluations to both trains, was performing cause evaluations on the repetitive operability evaluations, and planned to reconstitute the design basis for the system. This was captured in condition reports 54791, 54865, 55712, 55994, 56020, 56253, 56014, 56966, and 28252.

The failure to perform an operability evaluation that accurately reflected the plant design was a performance deficiency. The performance deficiency is more than minor because it impacted the design control attribute of the Mitigating Systems Cornerstone and affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences because the licensee had to re-perform the evaluations to demonstrate that adequate capability existed.

Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, this finding was determined to be of very low safety significance because operability evaluations were ultimately able to demonstrate adequate heat removal capability for the Class IE electrical equipment rooms. The inspectors identified the cause of the finding had a crosscutting aspect in the area of problem identification and resolution because Wolf Creek did not thoroughly evaluate the problem such that the resolutions address causes and extent of conditions, as necessary. Specifically, the reduced flow rate was a narrow focus of the evaluation and did not consider ongoing system design problems in evaluating the losses of margin

P.1.c]. (Section 1R15).

Green.

On July 9, 2012, the inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for inappropriately reducing the vital air conditioning unit fan flow rate test acceptance criteria to a value less than that used in the Updated Safety Analysis Report and supporting calculations. The inspectors identified that the train B air conditioning unit fan SGK05B improperly passed its surveillance test, procedure STS PE-16B, on June 8, 2011, at 10,472 cfm when the design flow rate is 11,500 cfm. A flow rate of 11,500 cfm was specified in all of Wolf Creeks design basis calculations. Reviewing the history, the inspectors found condition report 2001-3149 led to changing the test acceptance criteria on January 15, 2002. In that change, Wolf Creek misapplied standards for filtration and charcoal absorber units to the control building air conditioning units in order to justify reducing the minimum flow rate acceptance criteria by 10 percent for procedures STS PE-16A and -16B, Train A[B]

Class IE Elect System A/C System Flow Rate Verification, Revision 2. Wolf Creek initiated condition report 54791 and assessed the reduced flow rate impact in operability evaluation GK-12-011.

Changing surveillance test acceptance criteria by incorrectly applying standards while lowering the acceptance criteria below the minimum required flow rate is a performance deficiency. The performance deficiency is more than minor because it impacted the design control attribute of the Mitigating Systems Cornerstone and affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609,

Appendix AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., The Significance Determination Process (SDP) for Findings At-Power, this finding was screened to a Green because operability evaluation GK-12-011 demonstrated that the train B vital air condition unit had approximately 0.7 percent margin to cool the train B batteries, battery chargers, switchgear, and inverters.

Therefore, there was not a loss of operability or functionality of a risk significant component. This issue did not screen as significant for fires, floods, or seismic events.

The inspectors found the cause of the finding was not indicative of current performance because the inappropriate test procedure changes were made approximately 11 years ago (Section IR22).

Cornerstone: Occupational Radiation Safety

Green.

The inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.4.1.a, which resulted from a worker failing to follow radiation protection procedures. A radiation worker, in a high noise area, received an electronic alarming dosimeter dose rate alarm, but failed to immediately stop work, notify co-workers, leave the area, and contact health physics as instructed by the radiation work permit and procedures. In response, the licensee investigated the occurrence, coached the individual on human performance tool usage, and restricted the individuals access to the radiological controlled area. The licensee implemented actions to consider the use of dosimeters with enhanced sound, vibration alarms, and/or visual alarms. This issue was documented in the licensees corrective action program as condition report 56059.

The failure to follow radiation protection procedures was a performance deficiency. The performance deficiency was more than minor because, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern.

Additionally, the performance deficiency was similar to an example in Appendix E to Inspection Manual Chapter 0612, Power Reactor Inspection Reports - Examples of Minor Issues. Example 6(h) states that an issue is more than minor if an individual continues to work in a high radiation area after receiving an electronic dosimeter alarm without taking the prescribed procedural actions. Using the Occupational Radiation Safety Significance Determination Process, the inspectors determined the finding had very low safety significance because: (1) it was not an as low as is reasonably achievable finding, (2) there was no overexposure, (3) there was no substantial potential for an overexposure, and (4) the ability to assess dose was not compromised. This finding had a crosscutting aspect in the human performance area, resources component, because the licensee failed to ensure adequate equipment, such as volume enhanced alarming dosimeters, were available to assure nuclear safety H.2(d) (Section 2RS01).

Green.

The inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.4.1.a, resulting from the licensees failure to follow ALARA planning procedures. Nonsafety-related gaskets were used, inadequate walkdowns were conducted, and work activities were not planned in the most efficient manner.

Consequently, the collective dose for Radiation Work Permit 11-2000 was approximately 7.626 person-rem instead of the planned 2.1 person-rem. Corrective actions were still being evaluated.

The failure to implement ALARA planning in accordance with procedural guidance was a performance deficiency. This finding was greater than minor because it was associated with the Occupational Radiation Safety Cornerstone, exposure control attribute, and affected the cornerstone objective, in that, it caused increased collective radiation dose for occupational workers. Additionally, the finding was similar to example 6(i) in Appendix E to Inspection Manual Chapter 0612, Power Reactor Inspection Reports -

Examples of Minor Issues. This example states that an issue is more than minor if it results in a collective dose greater than 5 person-rem, and the actual dose exceeds the estimated dose by greater than 50 percent. Using the Occupational Radiation Safety Significance Determination Process, the inspectors determined the finding had very low safety significance because, although the finding involved ALARA planning and work controls, the licensees latest 3-year rolling average collective dose was less than 135 person-rem. This finding had a crosscutting aspect in the human performance area, associated with the work practices component because the ALARA Committee provided no feedback on the quality or comprehensiveness of the planning of Radiation Work Permit 11-2000, and radiation protection and maintenance supervisors failed to provide adequate oversight of daily ALARA activities H.4(c) (Section 2RS02).

Licensee-Identified Violations

Violations of very low safety significance or severity level IV that were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and associated corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Wolf Creek began the inspection period at 100 percent power on June 30, 2012. The same day an electro-hydraulic control fluid line supplying the No. 4 turbine control valve developed excessive leakage that would require the system to be drained. Reactor power was reduced to three percent and the turbine generator was taken offline. The unit returned to 100 percent power on July 2, 2012. On August 16, 2012, a wildfire in the vicinity of Madison, Kansas, caused structural damage to an offsite power line feeding the Wolf Creek substation. On August 18, 2012, Wolf Creek reduced power to 70 percent to ensure the turbine generator stability for the duration of the power line repairs and returned to 100 percent power that same day. The unit remained at 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Partial Walkdown

a.

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

Inspection Scope

• August 7, 2012, Essential service water train A during a planned maintenance outage of essential service water pump B

• August 8, 2012, Emergency diesel generator A during a planned maintenance outage of emergency diesel generator B

• August 14, 2012, Motor-driven auxiliary feedwater train A during a planned maintenance outage of motor-driven auxiliary feedwater pump B

• August 14, 2012, Turbine-driven auxiliary feedwater during a planned maintenance outage of motor-driven auxiliary feedwater pump B

• August 15, 2012, Turbine-driven auxiliary feedwater during a planned maintenance outage of motor-driven auxiliary feedwater pump B

• September 6, 2012, Train A offsite power alternate alignment

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore,

potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report (USAR), technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

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

b.

No findings were identified.

Findings

.2 Complete Walkdown

a.

On May 30, 2012, the inspectors performed a complete system alignment inspection of the control building ventilation system to verify the functional capability of the system.

The inspectors selected this system because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors inspected the system to review mechanical and electrical equipment lineups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

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

b.

Introduction.

The inspectors identified an unresolved item involving the licensing basis and cooling capability of the safety-related air conditioning units and the ability to cool Findings

both trains of safety-related switchgear, batteries, battery chargers, and inverters with a single train of cooling.

Description.

On May 29, 2012, Wolf Creek made an unplanned entry into Technical Requirements Manual (TRM) 3.7.23 at 4:45 p.m. for the vital switchgear air conditioning unit B being inoperable. An operator on rounds had noticed a low differential pressure across the air conditioning compressors oil pump that was close to the trip setpoint for the air conditioning unit. Wolf Creek decided to replace the compressor. Technical requirements manual (TRM) Limiting Condition for Operation 3.7.23 allows for 7 days restoring the air conditioning unit. Thereafter, TRM 3.7.23 requires entry into the technical specification action statements for the vital buses, switchgear, inverters, and batteries, which are cooled by this unit.

The inspectors questioned how the equipment that was required to be cooled by this cooling unit would be able to function without cooling. The licensee explained that they would open doors between trains to allow the functioning unit to cool both trains. The inspectors identified several concerns about the adequacy of the single unit to cool both trains, the current licensing basis supporting this practice, and the lack of an operability determination.

After further discussions, on May 31, 2012, Wolf Creek wrote condition report 53672 and requested a prompt operability determination on the inspectors concerns. The train B vital air conditioning unit was replaced and returned to service an hour later. The prompt operability determination was automatically cancelled by procedure. The senior reactor operator agreed with the need to evaluate a potential degraded/non-conforming condition, and wrote another condition report, 53703, to ensure that the reportability evaluation included sufficient analyses to justify or preclude future operation with a single air conditioning unit in operation.

On Monday June 4, 2012, at 3:24 a.m., the train A vital switchgear air conditioning unit tripped on low differential pressure across the oil pump. Wolf Creek entered TRM 3.7.23 and posted compensatory measures of opening doors and positioning box fans. No entry was made into technical specification action statements for electrical equipment.

Wolf Creek performed an immediate operability determination by initiating condition report 53710, which concluded that the train A vital switchgear and batteries were operable. This conclusion was based on room temperatures presently being below the operability limit of 104 °F, room temperatures historically not exceeding 104 °F when one air conditioning unit is out of service, and the allowance of compensatory measures per TRM 3.7.23. In condition report 53710, the senior reactor operator requested a prompt operability determination based on concerns previously raised by the inspectors. On June 4, 2012, Wolf Creek had a preliminary GOTHIC room temperature computer model that predicted temperatures of 100 degrees F. The inspectors raised several questions regarding operability. In response, Wolf Creek engineering continued to evaluate the room temperatures and returned a result of inoperable at 2:34 a.m. on June 6 and the shift manager entered Technical Specifications 3.8.4, 3.8.7, 3.8.9, 3.7.8, 3.8.1, and 3.0.3.

Operability evaluation GK-12-08 contained GOTHIC computer models that calculated DC switchboard room temperature slightly above the 104 degrees °F room temperature

limit in TRM 3.7.23. Technical Specification 3.0.3 was entered because there is no specific action for this cooling system, and by virtue of having an inoperable support system necessary to support their function, the licensee declared two inverters and two batteries inoperable, as well as declaring the train A AC and DC power distribution systems inoperable. A power reduction was commenced at 3:27 a.m. The train A vital air conditioning unit SGK05A repairs were completed and was declared operable at 5:05 a.m. and all action statements were exited.

From May 29 through August 30, the inspectors identified the following concerns:

(1) Wolf Creek relied on compensatory measures to open all doors between trains of batteries and switchgear, posting continuous fire watches, and using non-safety powered box fans to blow air between rooms. The inspectors questioned the reliability and cooling capability of these measures, which were used as a basis for assuring the operability of safety-related systems. Specifically:

a. the temporary equipment that did not have a safety-related power source with a diesel generator backup b. the temporary air flow paths did not appear to ensure adequate air flow between trains c. portions of the temporary air flow path and went through a corridor that was not cooled, allowing unaccounted-for heat as well as loss of cooled air, since there was no way to efficiently move all the cooled air to the other trains room d. the heat loads and cooling capacity were not adequately accounted for (see below)

(2) The licensees creation of TRM 3.7.23 appeared to conflict with existing technical specifications that covered the situation. Specifically, cooling was required to support the safety functions of the associated batteries, inverters and switchgear. The definition of operable in technical specifications stated that for a system to be considered operable, all necessary cooling systems must also be capable of performing their related support functions. Part 9900 guidance for assessing operability further states that, in order to be considered operable, an SSC must be capable of performing the safety functions specified by its design within the range of specified physical conditions, which would include room temperature. Creating a TRM LCO allowing the support system to be out of service would not alleviate the need to consider the impact to the operability of the supported systems.

(3) The inspectors found that the electrical equipment heat load evaluated in various revisions of calculation GK-06-W, SGK05A/B Class IE Electrical Equipment Rooms A/C Units, Single Unit Operations Capacity, did not appear to adequately account for heat sources, and may not have provided an adequate technical basis for credited heat removal:

a. Draft Revision 2 was non-conservatively low because it did not include heat from a swing battery charger.

b. Draft Revision 2 relied on a nonsafety air conditioning unit to cool the health physics area under the 4160V vital switchgear rooms. This effectively treated the floor as a plate-type heat exchanger, and credited an inefficient heat transfer mechanism with removing a considerable part of the switchgear room heat load.

In doing so, the licensee was crediting non-safety equipment with no diesel generator backup source of power for maintaining the safety-related switchgear operable.

c. Calculations for heat removal capability assumed that only sensible heat would be removed from the air. This was inappropriate because humidity is commonly present at the Wolf Creek site. This assumption was non-conservative because this assumption would not account for heat removal used to condense moisture from the air, and would overstate the calculated temperature reduction.

d. The inspectors found conflicting references and calculations with different specifications for the capability of the SGK05 units cooling coil. One standard used in design calculations was M-622.1-00133 Reselection Study, which was a vendor study and not a design basis calculation. Condition report 55265 was written to reconcile these standards.

e. Heat removal calculations did not account for the heat load in the mechanical equipment rooms containing the air conditioning units and the pressurization fans.

f. Sensible and latent heat added to the switchgear rooms by outside air from the control building pressurization fans were not included in calculations. During accidents, the control building pressurization fans add outside air to raise the pressure in the control building to minimize in-leakage, but would add sensible and latent heat that was not included in heat removal calculations.

g. The amount of heat absorption into the concrete structure of the building that was credited in licensee calculations did not include an adequate technical justification. Specifically, the methodology used was not documented, and the room temperatures calculated did not appear to show any significant heat-up of the room air before large heat transfer took place. The amount of cooling seemed disproportionately high for such a small temperature difference between air and concrete.

h. The capacity of the air conditioning units cooling coil used in calculation GK-06-W, Revision 2 was approximately 15 percent larger than other Wolf Creek specifications for this component without technical justification. Calculation GK-06-W, also had differing cooling coil capabilities without an explanation in the Assumptions section and the Methodology, Nomenclature and Computations section.

(4) The inspectors identified that the licensee had no valid control building system flow and temperature design drawings, and that the existing system flows had not been verified to

conform the design through testing. Wolf Creek initiated condition report 54095 to address this issue. Further, the licensee had identified that train B had degraded flow rates in certain portions of the system, further challenging heat removal capability.

(5) The inspectors noted that the licensee did identify a direct cause of oil degradation for the May 29, and June 4, 2012, trips or the direct cause of previous compressor trips.

The inspectors found that previous trips of the compressor on overpressure were similar to the May and June trips because the oil was becoming acidic and contaminated each time. Previous condition report 27014 did not identify a cause. It proposed more frequent oil and refrigerant changes, but this was never implemented. The inspectors examined the oil removed from the train B compressor in May 2012 and observed a large quantity of metal flakes and black sludge. The oil filter screen for both units was covered in black sludge. There were also what appeared to be copper metal shavings.

The qualitative oil test found the oil to be marginally acidic and in need of replacement.

Apparent cause 53709 on the June 4 trip of the train A unit did not identify a cause of the oil contamination despite lab analysis of the oil.

The above concerns must be addressed before an evaluation of the combined effect of these concerns can be performed. In response, Wolf Creek created a new corrective action, 02-04, in condition report 28252 to reconstitute the design basis of the vital air conditioning system. Wolf Creek also created action 02-05 in condition report 28252 to re-evaluate the environmental qualifications of the Class IE electrical equipment.

Pending licensee resolution of the above technical issues, the inspectors will be able to draw a conclusion. Additionally, Wolf Creek initiated condition reports 54155, 55729, 55712, 53549, 53472, 55552, 55551, 55265, 55076, 54234, 53798, 53793, 53791, 53785, 53710, 54865, 54791, 54095, 54652, 53796, 53709, 53703, 53696, 53685, 53672, 53671, 53625, 53393, and 53452.

Pending further evaluation of the above issues by the licensee, this issue will be tracked as unresolved item (URI)05000482/2012004-01, Determine Licensing Basis and Capability of One Vital Air Conditioning Unit to Cool Both Trains of Class IE Electrical Equipment.

1R05 Fire Protection

.1 Quarterly Fire Inspection Tours

a.

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

Inspection Scope

• July 31, 2012, North piping penetration room - 2000 elevation auxiliary building, fire area A-24

• July 31, 2012, South piping penetration room - 2000 elevation auxiliary building, fire area A-25

• August 26, 2012, Train B spent fuel pool cooling room - 2000 elevation fuel building, fire area F-2

• August 26, 2012, Train A spent fuel pool cooling room - 2000 elevation fuel building, fire area F-3

• September 15, 2012, Lower cable spreading room - 2026 elevation control building, fire area C-21

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

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

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

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

b.

No findings were identified.

Findings

.2 Annual Fire Protection Drill Observation

a.

On August 3, 2012, the inspectors observed fire brigade activation in response to a mock fire on the emergency diesel generator A. The observation evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were

(1) proper wearing of turnout gear and self-contained breathing apparatus;

(2) proper use and layout of fire hoses;

(3) employment of appropriate fire fighting techniques;

(4) sufficient firefighting equipment brought to the scene;

(5) effectiveness of fire brigade leader communications, command, and control;

(6) search for victims and propagation of Inspection Scope

the fire into other plant areas;

(7) smoke removal operations;

(8) utilization of preplanned strategies;

(9) adherence to the preplanned drill scenario; and

(10) drill objectives.

These activities constitute completion of one annual fire-protection inspection sample as defined in Inspection Procedure 71111.05-05.

b.

No findings were identified.

Findings

1R06 Flood Protection Measures

a.

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

Inspection Scope

• August 7, 2012, Cable vault MHE5B

These activities constitute completion of one bunker/manhole sample as defined in Inspection Procedure 71111.06-05.

b.

No findings were identified.

Findings

1R07 Heat Sink Performance

a.

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the train A centrifugal charging pump room cooler heat exchanger. 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 EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines; the licensee properly utilized biofouling controls; the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring Inspection Scope

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 in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 a.

Quarterly Review of Licensed Operator Requalification Program On September 11, 2012, the inspectors observed a crew of licensed operators in the plants simulator during requalification testing. The inspectors assessed the following areas:

Inspection Scope

• Licensed operator performance

• The ability of the licensee to administer the evaluations

• The modeling and performance of the control room simulator

• The quality of post-scenario critiques

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

b.

No findings were identified.

Findings

.2 Quarterly Observation of Licensed Operator Performance

a. Inspection Scope

On the night of July 30, 2012, the inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity and risk due to an electro-hydraulic control system leak on the No. 4 turbine control valve. The inspectors observed the operators performance of the following activities:

• Shift turnover crew brief

• Reactivity control plan review

• Pre-job brief for a power reduction to 10 percent for main turbine shutdown and isolation

• Power reduction from 100 percent - 60 percent reactivity control: rod insertion, withdrawal, and borations

In addition, the inspectors assessed the operators adherence to plant procedures, including AP 21-001, Conduct of Operations, and other operations department policies.

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

b.

No findings were identified.

Findings

1R12 Maintenance Effectiveness

a.

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

Inspection Scope

• Post accident neutron detector N61 circuit card failure

• Emergency diesel A fuel injector failure

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 two quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b.

No findings were identified.

Findings

1R13 Maintenance Risk Assessments and Emergent Work Control

a.

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:

Inspection Scope

• June 30, 2012, Electro-hydraulic control fluid leakage at turbine-control valve No. 4 and subsequent power reduction to eight percent for repair

• August 3, 2012, EDG A, tornado exhaust damper failed as-found testing

• August 6-12, 2012, Work week 307 weekly risk assessment

• August 18, 2012, Power reduction to repair Benton offsite power line

• September 14, 2012, Motor-driven auxiliary feedwater pump check valve testing performed during a residual heat removal pump planned maintenance outage

• September 20-21, 2012, Train B centrifugal charging pump room cooler motor failure and subsequent emergent work to replace

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 six maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b.

No findings were identified.

Findings

1R15 Operability Evaluations and Functionality Assessments

a.

The inspectors reviewed the following assessments:

Inspection Scope

• July 24, 2012, Residual heat removal voiding a valve EJV088

• August 30, 2012, GK 12-12 and GK12-11, SGK05A[B] Class 1E electrical equipment air conditioning unit A/B

The inspectors selected these operability and functionality assessments based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure technical specification operability was properly justified and to verify the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and USAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. Additionally, the inspectors 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 two operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

b.

Introduction.

On August 30, 2012, the inspectors identified a Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Findings

Drawings, for an operability evaluation that failed to adequately justify operability of safety-related electrical equipment.

Description.

The inspectors reviewed the June 8, 2011, performance of STS PE-16B, Train B Class IE Elect System A/C System Flow Rate Verification, Revision 3A, and found that the fan had passed with a flow rate of 10,472 cfm. On July 9, 2012, the inspectors identified that train B air conditioning unit SGK05B had a flow rate that was below its minimum design flow rate of 11,500 cfm. Wolf Creek initiated condition report 54791 and operability evaluation GK-12-011.

The inspectors reviewed operability evaluation GK-12-011 and several related calculations. Over the course of 2 months, the inspectors challenged various aspects of the calculations being used to support operability with the degraded fans flow rate. The inspectors identified that the operability evaluation for the degraded fan did not including all of the relevant heat load, such as the energy required to condense moisture from the air, the basis for the capacity of the cooling coil, and the technical justification for heat removal through the floor to the health physics area.

The inspectors also identified that the operability evaluation for the degraded fan did not consider a key single failure. If a single failure of one air conditioning unit occurred, the pressurization fans for both trains would still push air between trains. This is because both pressurization fans discharge into the train B 4160V switchgear room, then through fire dampers in the dividing wall into the adjacent train A 4160V switch gear room. Thus, one uncooled 4160V switchgear room still can heat the other 4160V switchgear room because the operable air conditioning unit forces air between switchgear rooms. When the licensee accounted for this increased heat load, they initially concluded that compensatory measures were needed to stop the second pressurization fan in order to maintain the system operable. Later, additional margin was identified as the quality of the evaluation improved.

Based on these discussions, Wolf Creek expanded the operability evaluation to include the train A vital switchgear air conditioning unit. After recalculation, the licensee was able to demonstrate that one vital air conditioning unit was capable of removing the heat introduced by both pressurization fans. The inspectors agreed with this aspect of Revision 5 of operability evaluation GK-12-11 and Revision 2 to operability evaluation GK 12-12. Subsequently, to increase margin, Wolf Creek was able to demonstrate that some electrical loads were less than that stated in calculation GK-E-001. Wolf Creek continued to make operability evaluations through GK 12-11, Revision 5, and GK 12-12, Revision 2, and found that each air conditioning unit was capable of cooling its associated train. Wolf Creek had approximately 0.7 to 2.7 percent margin between heating inputs and cooling capability for train B and A, respectively. These issues were captured in condition reports 53672, 55994, 56014, and 57526.

Analysis.

The failure to perform an operability evaluation that accurately reflected the plant design was a performance deficiency. The performance deficiency is more than minor because it impacted the design control attribute of the Mitigating Systems Cornerstone and affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences

because the licensee had to re-perform the evaluations to demonstrate that adequate capability existed. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, this finding was determined to be of very low safety significance because operability evaluations were ultimately able to demonstrate adequate heat removal capability for the Class IE electrical equipment rooms. The inspectors identified the cause of the finding had a crosscutting aspect in the area of problem identification and resolution because Wolf Creek did not thoroughly evaluate the problem such that the resolutions address causes and extent of conditions, as necessary. Specifically, the reduced flow rate was a narrow focus of the evaluation and did not consider ongoing system design problems in evaluating the losses of margin P.1.c].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires 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. Instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Step 6.2.6.1 of procedure AP 26C-004, Operability Determination and Functionality Assessment, Revision 24, requires, in part, that the capability to perform the specified safety function be provided in an evaluation that states if the system, structure, or component can perform considering the degraded condition, the best information available, and the consideration of consequential failures.

Contrary to the above, from July 9 to September 21, 2012, the licensee failed to accomplish operability evaluations, an activity affecting quality, in accordance with documented procedures. Specifically, the inspectors identified that the licensee failed to include and accurately account for key plant design information to justify the operability of the vital switchgear air conditioning units SGK05A and SGK05B and the supported Class IE electrical equipment. These evaluations were documented in multiple revisions of operability evaluations GK-12-11 and GK-12-12. Because this finding is of very low safety significance and was entered into the licensee corrective action program as condition reports 55994 and 53672, this violation is being treated as a NCV in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000482/2012004-02, Inadequate Operability Evaluation for a Degraded Switchgear Cooling Fan.

==1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications (71111.17)

==

.1 Evaluations of Changes, Tests, or Experiments

a. Inspection Scope

The inspectors reviewed seven evaluations to determine whether the changes to the facility or procedures, as described in the USAR, had been reviewed and documented in accordance with 10 CFR 50.59 requirements. The inspectors verified that, when changes, tests, or experiments were made, evaluations were performed in accordance with 10 CFR 50.59 and licensee personnel had appropriately concluded that the change,

test or experiment could be accomplished without obtaining a license amendment. The inspectors also verified that safety issues related to the changes, tests, or experiments were resolved. The team compared the safety evaluations and supporting documents to the guidance and methods provided in Nuclear Energy Institute (NEI) 96-07, "Guidelines for 10 CFR 50.59 Implementation," as endorsed by NRC Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments," to determine the adequacy of the safety evaluations.

The inspectors reviewed 29 samples of changes, tests, and experiments that licensee personnel determined did not require evaluations and verified that the licensee personnels conclusions were correct and consistent with 10 CFR 50.59.

The inspectors also verified that calculations, analyses, design change documentation, procedures, the USAR, the technical specifications, and plant drawings used to support the changes were accurate after the changes had been made. Documents reviewed are listed in the attachment.

These activities constitute completion of 7 samples of evaluations and 29 samples of changes, tests, and experiments that were screened out by licensee personnel as defined in Inspection Procedure 71111.17-04.

b. Findings

No findings were identified.

.2 Permanent Plant Modifications

a. Inspection Scope

The inspectors verified that calculations, analyses, design change documentation, procedures, the USAR, the technical specifications, and plant drawings used to support the modifications were accurate after the modifications had been made. The inspectors verified that modifications were consistent with the plants licensing and design bases.

The inspectors confirmed that revised calculations and analyses demonstrated that the modifications did not adversely impact plant safety. Additionally, the inspectors interviewed design and system engineers to assess the adequacy of the modifications.

These activities constitute completion of 13 samples of permanent plant modifications as defined in Inspection Procedure 71111.17 04, and specific documents reviewed during this inspection are listed in the attachment.

.2.1 Reinstall Shims for Whip Restraints FWR 10 and FWR 10A

The inspectors reviewed Change Package 011481, implemented to install additional shims at whip restraints FWR 10 and FWR 10A. The design basis function of the whip restraints is to protect the safety-related equipment from the impact of a pipe whip force after a pipe break. The restraints are installed at the arbitrary intermediate break and

terminal break locations per guidelines provided in the branch technical position MEB 3-1. The arbitrary intermediate breaks are the high stress points in the high-energy lines. The lower shims were installed to achieve full contact with the bottom portion of the pipe, to transfer the dead load to the supporting structure. The upper shims were installed to allow vertical pipe movement prior to load transfer. The inspector verified that the material for the shims and the welding requirements were in accordance with the requirements specified in specification C-202B. The inspectors reviewed the pipe support drawings and related pipe support and stress calculations to ensure they were revised to reflect pipe stress calculation 0520511-C-009 and calculation 0520511-C-010.

.2.2 Diesel Fuel Oil

The inspectors reviewed change package 013043 implemented to evaluate the acceptability of American Society of Testing and Materials (ASTM) document, ASTM D975-07, Standard Specification for Diesel Fuel Oils. The licensee had not allowed the use of any biodiesel blend, and had requested procurement engineering to determine if ASTM D7371, ASTM Standard Test Method for Determination of Biodiesel (Fatty Acid Methyl Esters) Content in Diesel Fuel Oil Using Mid Infrared Spectroscopy, would be an acceptable test method for detecting biodiesel fuel oil. The requirements would cover the following diesel engines:

• Emergency diesel generators

• Security emergency diesel generator

• Diesel-driven fire pump and diesel engine driver for diesel-driven fire pump

• Technical support center (TSC) diesel generator

• Emergency operating facility (EOF) diesel generator

The engineering disposition results were:

• ASTM D975-07 was approved for all applications listed above.

• ASTM D7371-07, or later edition, was an approved test method for detecting biodiesel in No. 2-D diesel fuel oil. Any test method, including Herguth Laboratorys HL-1141A, may be used if it meets or exceeds the resulting sensitivities of ASTM D7371-07.

• Diesel fuel oil engineering procurement requirements SM023924 (emergency diesel generator), SM028912, and SM028914 were revised to specify:

a. ASTM D 975-07 in lieu of latest revision b. Dimer acid lubricity additives shall not be used

No additional post modification testing was prescribed by this change package other than that already required by AP 16E-002, Post Maintenance Testing Development.

.2.3 Chemical Volume and Control System Pressurizer Auxiliary Spray Line Replacement

The inspectors reviewed change package 013191, implemented to replace several sections of the pressurizer auxiliary spray line that showed indications of unacceptable stress corrosion cracking. The replacement piping was the same material as the original piping, but required additional socket and butt welds in order to use the existing pipe bends. The inspectors reviewed calculations supporting the use of additional welds, updated pipe stress calculations, and the cause analysis of the cracking to verify that the new piping would continue to meet the safety analysis.

.2.4 Atmospheric Relief Valve Stem Repair

The inspectors reviewed change package 013222, implemented to evaluate the feasibility of using atmospheric relief valve stem SR80201017, lot 241442. The valve stem was on hold because it was identified on a commodity discrepancy report as having the stem hole mis-drilled and would not align with holes in the pilot, thus the pin used to connect the pilot to the stem could not be installed. During inspection of the stem in the warehouse, procurement engineering also noted some surface imperfections on the stem. The stem is symmetrical, with both ends having identical thread profiles (approximately 16 threads per inch) and thread lengths (11/2 inches). There were no machined keyways or shoulders in the stem, and the stem has a uniform outside diameter. Procurement engineering verified in the warehouse, that a pilot from warehouse stock - SR80201016 would thread onto the end where the new hole was proposed. Thus, the fit of the pilot to the stem in this location had been confirmed. The inspectors verified that there were no changes in form (other than the new hole) and the stem would still perform its function. Procurement engineering approved drilling a hole for the pin on the opposite end of the stem. Procurement engineering also approved removing any blemishes or surface imperfections on the stem by polishing. The inspectors determined that the proposed modification was acceptable.

.2.5 Refueling Water Storage Tank Leakage

The inspectors reviewed change package 013269, implemented to add a 24-inch manway to the side of the refueling water storage tank. The manway was added to allow access to the inside of the refueling water storage tank to perform vacuum box and dye penetrant nondestructive testing of welds to identify potential leakage paths. The inspectors reviewed the structural qualification calculations and condition reports to verify that the refueling water storage tank would continue to meet the safety analysis.

The inspectors walked down the refueling water storage tank manway to ensure installation of the modification was in accordance with design.

.2.6 Essential Service Water Electrical Manhole Dewatering Sump Pumps

The inspectors reviewed change package 013270, implemented to permanently install sump pumps that operate automatically in 10 essential service water electrical manholes. The manholes contain safety-related cables that had been previously found to be flooded, submerging the safety-related cables. This modification replaced the

temporary installed sump pumps installed under temporary modification TMO 09-005-XX-01. The approved permanent modification required the installation of drain piping, duplex sump pumps, fused-disconnects, generator transfer switches, cables-raceway piping, and associated pump control panels. The dewatering system package applies to the essential service water system electrical manholes, the onsite and offsite drainage system, and the construction yard loop power system. The inspectors performed a walkdown to ensure the external installation of the modification was in accordance with the design as access to the inside of the manholes was limited.

.2.7 Essential Service Water System Piping Replacement

The inspectors reviewed change package 013289, implemented to replace sections of the essential service water system. The essential service water system is a safety-related system that is designed to remove heat from plant components during post-fire or post-accident safe shutdown of the reactor or following a design basis accident.

During one of the base metal repairs being performed on the system at location Line EF228HBC-30 inches, the repair went through the pipe wall, resulting in a three-eighths inch diameter hole, 12 inches clockwise from top dead center, looking in the direction of flow. Engineering approved the base metal weld repair of the through-wall defects on the essential service water piping. The inspectors verified that the repairs were made in accordance with Section II, Part A (material specification),Section III, and Section XI of the ASME Boiler and Pressure Vessel Code.

.2.8 Inboard & Outboard Bearing Resistance Temperature Detectors (RTDs) for Centrifugal

Charging Pump Motors and Safety Injection Pump Motors

The inspectors reviewed change package 013318, implemented to purchase and place in the warehouse replacement RTDs for the centrifugal charging pump motors and the safety injection pump motors. The Westinghouse motor part numbers for these devices were found to be obsolete. The licensee consulted with Westinghouse to obtain new part numbers for the centrifugal charging pump and safety injection pump motor RTDs.

New stock numbers were generated to purchase and stock the new RTDs for the centrifugal charging pump motors (No. SR90451299) and for the safety injection pump motors (No. SR90451300). No motor RTDs were replaced at this time, but the proper replacement parts have been acquired and are available for installation when required.

.2.9 Essential Service Water Motor Refurbishment

The inspectors reviewed change package 013325, implemented to correct deficiencies found during refurbishment of an essential service water motor by Schulz Electric under purchase order 748443. Paint chipping was identified in the upper and lower bearing oil reservoirs and required removal & repainting. The damaged area was repaired and repainted by Schulz Electric with a paint that was purchased and provided by the licensee. Also, there were some minor blemishes identified (drag marks on shaft and dent in end-bell) that had not been repaired during refurbishment activities, as these minor blemishes were determined by engineering to not affect the operation of the motor.

.2.10 Essential Service Water Isolation Gate Valve Replacement Material Change

The inspectors reviewed change package 013340, implemented to find a suitable valve replacement for carbon steel valves in the essential service water system which were experiencing erosion of the internals. The change included an alternate valve material and installation requirements. The need to replace essential service water isolation gate valve EFV-0063 was identified during the attempted replacement of containment spray pump room cooler SGL13B. The licensee identified that the isolation valve was leaking at 30 drops per minute. The licensee determined that the valve needed to be repaired or replaced to provide 100 percent isolation in the event welding needed to take place during the next room cooler replacement. The valve performs a passive safety function to insure an intact pressure boundary and structural integrity. The valve serves no active safety function. The inspectors determined that a valve made of stainless steel in lieu of carbon steel does not change the safety functions nor the credible failure modes documented in SCA-93-0193.

.2.11 Broken Wires in Containment Tendon V7 and V65

The inspectors reviewed change package 013427, implemented to resolve concerns identified while conducting the 25th Year Containment Tendon Surveillance at Wolf Creek, as required by Wolf Creek Nuclear Operating Corporation (WCNOC)

Procedure STS MT-044, Containment Tendon Inspection and Specification C-158(Q),

Technical Specification for Containment Tendon Surveillance. The inspection revealed that wires in two vertical tendons were found broken and/or damaged. For vertical tendon V7: two wires at the south end were found broken after completing the lift-off force test. Also, some other wires were found damaged or protruding, but not broken.

For vertical tendon V65: two wires at the east end were found broken after completing the lift-off force test.

• For tendon V7, the calculated material stress was = 161.9 ksi. Calculation 01-116-F, PTS Stress Relaxation Curves for Inservice Tendon Surveillance, Tendons at Wolf Creek, Attachment B, page three, shows the predicted upper and lower bounds of tendon wire stress tolerance band for tendon V7 over a period of over 40 years. The inspectors verified that a stress value of 161.9 ksi was within the acceptable range, thus acceptable as is.

• For tendon V65, the calculated material stress was = 162.8 ksi. Calculation 01-116-F, PTS Stress Relaxation Curves for Inservice Tendon Surveillance, Tendons at Wolf Creek, Attachment B, page 20, shows the predicted upper and lower bounds of tendon wire stress tolerance band for tendon V65 over a period of over 40 years. The inspectors verified that a stress value of 162.8 ksi was within the acceptable range, thus acceptable as is.

It was concluded that the loss of wires as reported in PSC NCR report No. FN1054-001 and NCR Report No. FN1054-002 had an insignificant impact on the overall pre-

stressing effect and, also, that the material stresses in the remaining wires were within the code allowable acceptable range.

.2.12 Alternate Magnetrol Level Switch

The inspectors reviewed change package 013524, implemented to approve a replacement for the obsolescent Magnetrol level switch model No.

BC-751-MP-X-S1MD4C, which was no longer available for purchase. The Magnetrol level switch model No. B35-PB30-CNA and Magnetrol 1-inch to 3/4-inch conduit reducer, part number 09-2601-001, together, have been evaluated by engineering to be an acceptable replacement for the obsolete level switches. There were some dimensional differences (the new units have larger switch housings) in the replacement level switches that would require slight piping changes to be incorporated, when installed. No level switches were replaced at this time. The new level switches were purchased as spares and were tagged SPARE.

.2.13 Replacement for 43-1-C5 & 43-2-C5 Transfer Switches of the Emergency Diesel

Generator Voltage Regulator and Excitation System

The inspectors reviewed change package 013596, implemented to approve an alternate replacement hand switch for the obsolete Electroswitch part No. CC125-0910C8-001-7811 which is used as the transfer switch for the emergency diesel generators voltage regulator and static exciter system. The switches are located in panels NE106 and NE107, identified in the applicable drawings as 43-1-C5 and 43-2-C5 within each panel. The licensee evaluated and determined that Electroswitch part number KW100-910C8-2 would be an acceptable replacement for the obsolete switch.

The inspectors reviewed the licensees engineering evaluation to verify that the old and new switches perform electrically the same with only minor mounting differences between the two. The new transfer switches will be stocked in the warehouse and were not required to be installed at this time.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 a.

Permanent Modifications 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 for installation of the turbine-driven auxiliary feedwater standby tanks.

Inspection Scope

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; post-modification 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 71111.18-05.

b.

No findings were identified.

Findings

1R19 Postmaintenance Testing

a.

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

Inspection Scope

• July 1 - 2, 2012, Electro-hydraulic control fluid supply to turbine control valve No. 4 tubing leak repairs

• August 8, 2012, Emergency diesel generator B postmaintenance run

• August 9, 2012, Essential service water B to normal service water cross-connect valve and essential service water B to normal service water isolation valve stroke testing

• August 14, 2012, Stroke testing of motor-driven auxiliary feedwater pump B suction valve and discharge valve D

• August 16, 2012, NK021 125Vdc battery charger semi-annual preventive maintenance

• August 28, 2012, Reactor coolant system wide range temperature instrument card replacement

• August 29, 2012, Centrifugal charging pump A lube oil gauge replacement

• September 7, 2012, Wolf Creek switchyard breaker 13-48 air tank replacement

• September 25, 2012, Auxiliary building tornado damper GFD0043 lube and spring adjustment following as-found testing failure

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 post-maintenance 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 nine postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b.

No findings were identified.

Findings

1R22 Surveillance Testing

a. Inspection Scope

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

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• 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.

• June 9, 2012, Train B air conditioning unit SGK05B fan flow rate testing

• July 12, 2012, Startup main feedwater pump operational test (not an in-service test)

• July 19, 2012, Reactor coolant system pressure isolation valve leakage quantification using TMP 12-08, SI Test Line Leak Quantification

• August 29, 2012, Containment purge valve leakage test (containment isolation valve)

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

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

b.

Introduction.

On July 9, 2012, the inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for inappropriately reducing the Findings

vital air conditioning unit fan flow rate test acceptance criteria to a value less than that used in the design basis and supporting calculations.

Description.

On July 9, 2012, the inspectors identified that the train B fan for safety-related air conditioning unit SGK05B had previously failed its surveillance test because it did not provide the minimum design basis flow rate. The inspectors reviewed the June 8, 2011, performance of STS PE-16B, Train B Class IE Elect System A/C System Flow Rate Verification, Revision 3A, and found that the fan met the specified acceptance criteria with a flow rate of 10,472 cfm.

The inspectors compared this result with USAR, Chapter 9.4.1, Control Building HVAC.

USAR, Table 9.4-4, specifies a minimum design flow rate of 11,500 cfm for each air conditioning unit. A minimum flow rate of 11,500 cfm was also used in Wolf Creek design basis calculations for vital electrical switchgear room temperatures. The inspectors examined the history of the acceptance criteria in procedure STS PE-16B and 16A. The fan for air conditioning unit SGK05B had previously failed a surveillance test on December 16, 2001. A ventilation damper was found mispositioned, and SGK05B passed its re-test on December 18, 2001, with a flow rate of 11,785 cfm. Wolf Creek initiated condition report 2001-3149 and subsequently changed the test acceptance criteria on January 15, 2002. In its basis for the procedure change, Wolf Creek cited ASME N510-1980, Testing of Nuclear Air Treatment Systems, in its condition report, document revision request, and 10 CFR 50.59 applicability determination. Wolf Creek did not cite any specific section of ASME N510-1980, but stated that there was an allowance of plus or minus 10 percent per ASME N510. The minimum acceptance criterion of 11,500 cfm was thus adjusted down to 10,350 cfm.

The inspectors reviewed Regulatory Guide 1.52, Design, Testing and Maintenance Criteria for Post-Accident Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants, Revision 2, and the Wolf Creek design comparison to this Regulatory Guide in USAR, Table 9.4-2.

Regulatory Guide 1.52 endorses, in part, the guidance in ASME N510-1980, Testing of Nuclear Air Treatment Systems. The inspectors found that Section 8.3.8 states Acceptance Criteria. Flow shall be within [plus or minus] 10 [percent] of system design flow. The inspectors also found that per USAR, Table 9.4-4, Regulatory Guide 1.52, only applied to the emergency exhaust system, the control room filtration system, and the pressurization system because they all contained high efficiency particulate air filters and charcoal adsorbers. The inspectors concluded that Wolf Creek incorrectly applied these standards to the control building air conditioning units, and in doing so, failed to ensure that the acceptance criteria verified that the minimum air flow rate needed to support operability and adequate cooling for vital switchgear, inverters, and batteries.

The inspectors brought this to the attention of Wolf Creek, which initiated condition report 54791 and operability evaluation GK-12-011. Initially, Wolf Creek engineering attempted to justify the application of the standards for the reduced acceptance criteria.

Wolf Creek senior management subsequently assured the inspectors that the acceptance criteria would be restored to the design basis criteria. Lastly, the inspectors observed that there is no regularly scheduled test of the system flow balance and Wolf Creek initiated condition report 54095 for this concern. See Section 1R15 for results of the inspection of operability evaluation GK-12-011.

Analysis.

Changing surveillance test acceptance criteria by incorrectly applying standards while lowering the acceptance criteria below the minimum required flow rate is a performance deficiency. The performance deficiency is more than minor because it impacted the design control attribute of the Mitigating Systems Cornerstone and affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, this finding was screened to a Green because operability evaluation GK-12-011 demonstrated that the train B vital air condition unit had approximately 0.7 percent margin to cool the train B batteries, battery chargers, switchgear, and inverters.

Therefore, there was not a loss of operability or functionality of a risk significant component. This issue did not screen as significant for fires, floods, or seismic events.

The inspectors found the cause of the finding was not indicative of current performance because the inappropriate test procedure changes were made approximately 11 years ago.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Wolf Creek procedures STS PE-16A[B], STS PE-16A[B], Train A[B] Class IE Elect System A/C System Flow Rate Verification, Revision 3A, tests vital air conditioning unit fan flow rates to assure that USAR, Table 9.4-2, minimum flow rate of 11,500 cfm can be met. Contrary to the above, test procedures used to demonstrate that the vital switchgear cooling fans will perform satisfactorily in service failed to incorporate the requirements and acceptance limits contained in applicable design basis documents. Specifically, from January 15, 2002, to the present, procedures STS PE-16A and -16B contained a minimum allowed flow rate of 10,350 cfm, while design basis documentation required a minimum of 11.500 cfm. Because this finding is of very low safety significance and was entered into the licensee corrective action program as condition report 54791, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000482/2012004-03, Safety-Related Fan Flow Rate Acceptance Criteria Reduced Below Design Basis Limit.

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspector discussed with licensee staff the operability of offsite emergency warning systems and backup alerting methods, to determine the adequacy of licensee methods for testing the alert and notification system in accordance with 10 CFR Part 50, Appendix E. The licensees alert and notification system testing program was compared with the following:

• NUREG-0654, A Criteria for Preparation and Evaluation of Radiological

Emergency Response Plans and Preparedness in Support of Nuclear Power Plants (Revision 1),

• FEMA Report REP-10, A Guide for the Evaluation of Alert and Notification Systems for Nuclear Power Plants,

The FEMA-approved design for the licensees alert and notification system is addressed in the following documents:

• Wyle Research Report WR 84-21 (September 1985) with reference to Tone Alert Radio system design;

• Wolf Creek Generating Station Site-Specific Off-Site Radiological Emergency Preparedness Alert and Notification System Quality Assurance Verification (1987) with reference to Tone Alert Radio system design; and

• REP-10 Design Review Report, Wolf Creek Nuclear Operating Company (2008) with reference to siren system design.

The specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.02.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation

a. Inspection Scope

The inspector discussed with licensee staff the operability of primary and backup systems for augmenting on-shift staff to determine the adequacy of licensee methods for staffing emergency response facilities in accordance with their emergency plan and the requirements of 10 CFR Part 50, Appendix E, including provisions for staffing alternate or backup facilities. The inspector also reviewed licensee training on augmentation procedures, augmentation system testing programs, and selected entries in the licensee corrective action system related to emergency response facility staffing. The specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.03.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)

a. Inspection Scope

The NSIR Headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession number ML12187A218 as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment.

These activities constitute completion of three samples as defined in Inspection Procedure 71114.04-05.

b. Findings

No findings were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed:

• Licensee corrective action program requirements in Procedure AP 28A-100, Condition Reports, Revision 17;

• Summaries of one hundred sixty-five corrective action program entries (Condition Reports) assigned to the emergency preparedness department and emergency response organization between July 2010 and June 2012;

• Licensee audits, assessments, drill evaluations, and post-event after action reports conducted between July 2010 and June 2012;

• Memorandum of Understanding between the licensee and offsite agencies and organizations relied upon to support site emergency response efforts;

• Licensee procedures and training for the evaluation of changes to the site emergency plans;

• Maintenance records for equipment relied upon to support site emergency response efforts; and,

• Alternate facilities for the licensees Emergency Operations Facility (EOF).

The inspector selected 27 condition reports for detailed review against the program requirements. The inspector evaluated the response to issues entered into the site corrective action program to determine the licensees ability to identify, evaluate, and correct problems in accordance with the licensee program requirements, planning standard 10 CFR 50.47(b)(14), and 10 CFR Part 50, Appendix E. The specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a.

The inspectors evaluated the conduct of a routine licensee emergency drill on August 9, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator and technical support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the attachment.

Inspection Scope

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

b.

No findings were identified.

Findings

2RS0 1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

This area was inspected to:

(1) review and assess licensees performance in assessing the radiological hazards in the workplace associated with licensed activities and the implementation of appropriate radiation monitoring and exposure control measures for both individual and collective exposures,

(2) verify the licensee is properly identifying and reporting Occupational Radiation Safety Cornerstone performance indicators, and

(3) identify those performance deficiencies that were reportable as a performance indicator and which may have represented a substantial potential for overexposure of the worker.

The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspectors performed walkdowns of various portions of the plant, performed independent radiation dose rate measurements and reviewed the following items:

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

• The hazard assessment program, including a review of the licensees evaluations of changes in plant operations and radiological surveys to detect dose rates, airborne radioactivity, and surface contamination levels

• Instructions and notices to workers, including labeling or marking containers of radioactive material, radiation work permits, actions for electronic dosimeter alarms, and changes to radiological conditions

• Programs and processes for control of sealed sources and release of potentially contaminated material from the radiologically controlled area, including survey performance, instrument sensitivity, release criteria, procedural guidance, and sealed source accountability

• Radiological hazards control and work coverage, including the adequacy of surveys, radiation protection job coverage, and contamination controls; the use of electronic dosimeters in high noise areas; dosimetry placement; airborne radioactivity monitoring; controls for highly activated or contaminated materials (non-fuel) stored within spent fuel and other storage pools; and posting and physical controls for high radiation areas and very high radiation areas

• Radiation worker and radiation protection technician performance with respect to radiation protection work requirements

• Audits, self-assessments, and corrective action documents related to radiological hazard assessment and exposure controls since the last inspection

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

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.01-05.

b. Findings

Introduction.

The inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.4.1.a, resulting from a worker failing to follow radiation protection procedures. The violation had very low safety significance.

Description.

On August 13, 2012, a radworker was performing boron walk downs in the Letdown Heat Exchanger valve rooms when he received two dose rate alarms. He was signed onto Radiation Work Permit (RWP) 120010, Task 3. The RWP task had a dose limit of 25 millirem and a dose rate limit of 150 millirem per hour. If either of these limits were reached, the radworker was instructed to stop work. The actual peak dose rate received was 212 millirem per hour. Step 6.2.6 of procedure AP 25B-100, Radiation Worker Guidelines, Revision 44, states that if a radworkers electronic alarming dosimeter alarms with a dose rate alarm, the worker shall notify co-workers and health physics. The individual was in a high noise area and stated that he checked his dosimeter twice and did not notice an alarm and thus, failed to stop work and contact radiation protection personnel as required. The alarms were confirmed upon logging out of the radiological controlled area. The survey reviewed for this issue showed that the maximum dose rate in the area was 220 millirem per hour on contact and 140 millirem per hour at 30 cm. Thus, the area was posted and verified as a high radiation area.

In response to the event, the licensee investigated the occurrence, coached the individual on human performance tool usage, and restricted the individuals access to the radiological controlled area. The licensee has implemented actions to consider the use of dosimeters with enhanced sound, vibration alarms, and/or visual alarms.

Analysis.

The failure to follow radiation protection procedures was a performance deficiency. The performance deficiency was more than minor because, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Additionally, the performance deficiency was similar to an example in Appendix E to Inspection Manual Chapter 0612, Power Reactor Inspection Reports - Examples of Minor Issues. Example 6(h) states that an issue is more than minor if an individual continues to work in a high radiation area after receiving an electronic dosimeter alarm without taking the prescribed procedural actions. Using the Occupational Radiation Safety Significance Determination Process, the inspectors determined the finding had very low safety significance because:

(1) it was not an as low as is reasonably achievable finding,

(2) there was no overexposure,

(3) there was no substantial potential for an overexposure, and

(4) the ability to assess dose was not compromised. This finding had a crosscutting aspect in the human performance area, resources component, because the licensee failed to ensure adequate equipment, such as volume enhanced alarming dosimeters, were available to assure nuclear safety

H.2(d).

Enforcement.

Technical Specification Section 5.4.1.a requires that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A to Regulatory Guide 1.33, Quality Assurance Program Requirements, Revision 2, February 1978. Section 7.e of Regulatory Guide 1.33 requires radiation protection procedures for access control to radiation areas, including a Radiation Work Permit (RWP). RWP 120010 had a stop work dose rate limit of 150 millirem per hour. Additionally, step 6.2.6 of procedure AP 25B-100 states that if a radworkers electronic alarming dosimeter alarms with a dose rate alarm, the worker shall notify co-workers and health physics. Contrary to these requirements, on August 13, 2012, a radiation worker failed to implement written radiation protection

procedures for access control to radiation areas. Specifically, the worker failed to comply with his RWP and procedural requirements when he received a dose rate alarm and failed to immediately stop work, notify co-workers, leave the area, and contact radiation protection personnel as instructed. Since this violation was of very low safety significance and was documented in the licensees corrective action program as condition report 00056059, it is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000482/2012004-04, Failure to Follow Radiation Protection Procedures.

2RS0 2 Occupational ALARA Planning and Controls

a. Inspection Scope

This area was inspected to assess performance with respect to maintaining occupational individual and collective radiation exposures ALARA. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance.

During the inspection, the inspectors interviewed licensee personnel and reviewed the following items:

• Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements

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

• The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies

• Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry

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

• Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection

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

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.02-05.

b. Findings

Introduction.

The inspectors reviewed a Green, self-revealing, non-cited violation of Technical Specification 5.4.1.a resulting from the licensees failure to follow ALARA planning procedures.

Description.

RWP 11-2000, Mechanical Maintenance, was originally estimated to accrue a total dose of 2.121 person-rem. However, the radiation work permit actually accrued 7.626 person-rem. During interviews with licensee representatives, the inspectors determined the licensee revised the radiation work permit to add valve work multiple times. Normally, an increase in work scope is a legitimate reason for revising a dose estimate. However, the licensee did not plan the additional work. Instead, it only raised the dose estimate of the radiation work permit as dose accrued.

The inspectors reviewed the licensees radiation work permit preparation guidance and noted the licensee had not followed the instructions. Procedure RPP 02-105, RWP, Revision 35, step 9.2, Assigning Work to an Existing RWP Number, lists six criteria that must be met. Licensee representatives acknowledged they had not met the criterion which stated, Work [added to an existing RWP] will not change current RWP exposure goal or estimate. Had the licensee complied with this requirement, it would have generated a new RWP, rather than simply adding work to an existing RWP. Licensee representatives acknowledged generating a new RWP would have prompted them to plan the additional work according to procedural guidance, as was the original work.

Licensee representatives also stated that ALARA planning was adversely affected by inadequate communication between the maintenance department and radiation protection personnel. The inadequate communication caused the ALARA planners to be unaware of the full scope of the work that needed to be performed. The inspectors noted the ALARA committee reviewed a proposed dose estimate to RWP 11-2000 on April 12 and May 3, 2011, but provided no feedback on the quality or comprehensiveness of planning. According to the licensees guidance, one of the responsibilities of the ALARA committee is to evaluate RWP packages with an estimated dose greater than or equal to 1 rem. Licensee representatives stated there was a lack of management oversight during the outage by radiation protection supervisors, maintenance supervisors, and ALARA committee members to ensure the ALARA planners understood and followed the existing RWP planning guidance.

As a result of the lack of ALARA planning, the post-job review and ALARA Committee minutes that addressed RWP 11-2000 stated, This RWP had multiple problems. The problems included the use of nonsafety-related gaskets that were used inappropriately and required the reworking of valves. A valve (BMV0023) found next to letdown piping indicated that an adequate walkdown or review of the area had not been conducted to indentify the hazards or, if a review had been conducted, the information had not been provided to the ALARA planner. Also, inspections of hangers by quality assurance personnel were not planned to ensure they were conducted in the most efficient manner.

All of these problems added unplanned, unintended dose to this work activity.

Because it would be instrumental in the analysis of the significance of a finding or violation, the inspectors reviewed NUREG-0713, Occupational Radiation Exposure at

Commercial Nuclear Power Reactors and Other Facilities, Volume 33, Table 4.8, and found the licensees 3-year rolling average collective dose for years 2009 through 2011 was 72.704 person-rem.

Analysis.

The failure to implement ALARA planning in accordance with procedural guidance was a performance deficiency. This finding was greater than minor because it was associated with the Occupational Radiation Safety Cornerstone, exposure control attribute, and affected the cornerstone objective in that it caused increased collective radiation dose for occupational workers. Additionally, the finding was similar to example 6(i) in Appendix E to Inspection Manual Chapter 0612, Power Reactor Inspection Reports Examples of Minor Issues. This example states that an issue is more than minor if it results in a collective dose greater than 5 person-rem, and the actual dose exceeds the estimated dose by greater than 50 percent. Using the Occupational Radiation Safety Significance Determination Process, the inspectors determined the finding had very low safety significance because, although the finding involved ALARA planning and work controls, the licensees latest 3-year rolling average collective dose was less than 135 person-rem. This finding had a crosscutting aspect in the human performance area, associated with the work practices component because the ALARA Committee provided no feedback on the quality or comprehensiveness of the planning of RWP 11-2000, and radiation protection and maintenance supervisors failed to provide adequate oversight of daily ALARA activities H.4(c).

Enforcement.

Technical Specification 5.4.1.a required procedures be established, implemented, and maintained covering activities specified in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, Section 7.e of Regulatory Guide 1.33 specified procedures for access control to radiation areas, including a RWP system and implementation of an ALARA program. Procedure RPP 02-105, RWP, Revision 36, implements this requirement and step 9.2.1 states, Health Physics may assign work to an existing radiation work permit number when work will not change the current radiation work permit exposure goal or estimate. Contrary to the above, on April 12 and May 3, 2011, the licensee failed to implement written radiation protection procedures for access control to radiation areas. Specifically, a licensee representative assigned work to an existing RWP (11-2000), which changed the current RWP exposure estimate. The licensee placed the violation in the corrective action program and corrective actions are still being evaluated. The violation does not constitute an immediate safety concern because the licensee is not currently conducting a refueling outage. Because this violation is of very low safety significance and has been entered into the licensees corrective action program as condition report 00058147, it is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy:

NCV 05000482/2012004-05, Failure to Follow ALARA Planning Procedures.

OTHER ACTIVITIES

Cornerstones: Mitigating Systems, Emergency Preparedness, and Occupational Radiation Safety

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspector reviewed data submitted by the licensee for the fourth quarter 2011, first quarter 2012, and second quarter 2012 performance indicators to identify any obvious inconsistencies prior to its public release in accordance with Inspection Manual 0608, Performance Indicator Program.

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

b. Findings

No findings were identified.

.2 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspector sampled licensee submittals for the Drill and Exercise Performance performance indicator for the period October 2011 to June 2012. Performance indicator definitions and guidance in NEI Document 99-02, Regulatory Assessment Performance Indicator Guidance, Revision 6, were used to determine the accuracy of the performance indicator data reported during those periods. The inspector reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the NEI guidance.

Specifically, the inspector reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator; assessments of performance indicator opportunities during pre-designated control room simulator training sessions, and other drills. The specific documents reviewed are described in the attachment to this report.

The activities constitute completion of the drill/exercise performance sample as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspector sampled licensee submittals for the emergency response organization drill participation performance indicator for the period October 2011 to June 2012.

Performance indicator definitions and guidance in NEI Document 99-02, Regulatory Assessment Performance Indicator Guidance, Revision 6, were used to determine the accuracy of the performance indicator data reported during those periods. The inspector reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the NEI guidance. Specifically, the inspector reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator; rosters of personnel assigned to key emergency response organization positions, and exercise participation records. The specific documents reviewed are described in the attachment to this report.

The activities constitute completion of one drill/exercise performance sample as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.4 Alert and Notification System (EP03)

a. Inspection Scope

The inspector sampled licensee submittals for the alert and notification system performance indicator for the period October 2011 to June 2012. Performance indicator definitions and guidance in NEI Document 99-02, Regulatory Assessment Performance Indicator Guidance, Revision 6, were used to determine the accuracy of the performance indicator data reported during those periods. The inspector reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the NEI guidance. Specifically, the inspector reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator and the results of periodic alert notification system operability tests. The specific documents reviewed are described in the attachment to this report.

The activities constitute completion of the drill/exercise performance sample as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.5 Mitigating Systems Performance Index - Emergency AC Power System (MS06)

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - emergency ac power system performance indicator for the period from the third quarter 2011 through the second quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2011 through June 2012 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one mitigating systems performance index - emergency ac power system sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

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

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - high pressure injection systems performance indicator for the period from the third quarter 2011 through the second quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of July 2011 through June 2012, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one mitigating systems performance index - high pressure injection system sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

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

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for the period from the third quarter 2011 through the second quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of July 2011 through June 2012, to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one mitigating systems performance index - cooling water system sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.8 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the second quarter 2011 through the second quarter 2012. The objective of the inspection was to determine the accuracy and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

The inspectors reviewed corrective action program records associated with high radiation area (greater than 1 rem/hr) and very high radiation area non-conformances.

The inspectors reviewed radiological, controlled area exit transactions greater than 100 mrem. The inspectors also conducted walkdowns of high radiation areas (greater than 1 rem/hr) and very high radiation area entrances to determine the adequacy of the controls of these areas.

These activities constitute completion of one occupational exposure control effectiveness sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.9 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the second quarter 2011 through the second quarter 2012. The objective of the inspection was to determine the accuracy and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

The inspectors reviewed the licensees corrective action program records and selected individual annual or special reports to identify potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose.

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

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

a.

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees Inspection Scope

corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

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

b.

No findings were identified.

Findings

.2 Daily Corrective Action Program Reviews

a.

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

Inspection Scope

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.

No findings were identified.

Findings

.4 Selected Issue Follow-up Inspection

a.

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting the ground cover depth requirements for buried essential service water piping and cable trays in regards to ongoing construction projects throughout the site. The inspectors reviewed the basis and margin for the existing design basis requirements. The inspectors also reviewed construction quality assurance records and recent topographical survey data to confirm that adequate margin existed.

Inspection Scope

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

b.

No findings were identified.

Findings

.5 Selected Issue Follow-up Inspection

a.

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting the condition of oil in the Terry turbine for the turbine-driven auxiliary feedwater pump. The inspectors reviewed the corrective actions from licensee event report (LER) 2011-009-01 and condition report 42635. The inspectors reviewed the basis for Wolf Creek reducing its generic International Standards Organization contamination code acceptance criteria in I-ENG-004, Lubricating Oil Analysis for the alert limit. The inspectors compared the new limit to the recommendations in the Electric Power Research Institute (EPRI) Terry Turbine Maintenance Guide, [Auxiliary Feedwater Application]. The inspectors also reviewed EPRI recommendations that were not incorporated, such as monthly testing of oil for water content. The inspectors found that Wolf Creek did not adopt this guidance, but that recent oil testing has shown very low levels of water. The inspectors found that the latest vendor information was not incorporated into Wolf Creeks vendor manual for the turbine and governor.

Inspection Scope

The inspectors observed that Wolf Creek replaced its 25 micron filter with a vendor recommended 5 micron filter in September 2012 and the oil testing results were showing International Standards Organization particle count results comparable to that of new oil.

The inspectors also compared recorded quarterly pump testing parameters to the EPRI guidance. EPRI recommends collecting a minimum of six items for troubleshooting or performance monitoring during any test. Those consisted of turbine speed, pump discharge flow, pump discharge pressure, ramp generator and signal converter output, EG-M control box output, and transient position of the turbine governor valve, using a low-tension linear potentiometer. Pump flow and pressure are recorded by the plant computer, but the governor electronics are only monitored yearly. Inspectors reviewed the most recent governor data and found no anomalies.

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

.b No findings were identified.

Findings

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 Closed:

URI 05000482/2011-004-04, Excessive Oil Contamination for Turbine Driven Auxiliary Feedwater Pump, and LER 2011-009-00, 01, Inadequate Oil Analysis Caused Inoperable Auxiliary Feedwater Pump Longer Than Required Action Completion Time

On August 11, 2011, Wolf Creeks oil sampling program received laboratory results for the turbine side of the turbine-driven auxiliary feedwater pump. The oil analysis had high particulates greater than the required action level, so Wolf Creek declared the pump inoperable. Wolf Creek requested and received enforcement discretion to extend the allowed outage time in order to clean up the particulate in the oil. The oil was filtered and exchanged several times and returned to service by August 14, 2012. In February 2012, the combined oil system of the Terry turbine and governor was disassembled and cleaned. The electronic governor regulator to pedestal adapter had significant corrosion and was cleaned. Vendor analyses of the electronic governor regulator found that degraded performance and eventual failure was a likely outcome. The inspectors reviewed both versions of the licensee event reports, observed repairs in February 2012, reviewed the apparent cause determination, and reviewed corrective actions. See Section 4OA2 for the selected issue follow-up inspection of this issue. The first LER was submitted pursuant to 10 CFR 50.73(a)(2)(I)(B) to report exceeding the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> technical specification required action completion time for the turbine-driven auxiliary feedwater pump. Supplemental LER 2011-009-01 was submitted to also report this event in accordance with 10 CFR 50.73(a)(2)(ii)(B), 10 CFR 50.73(a)(2)(v)(B), and 10 CFR 50.73(a)(2)(v)(D). The inspectors found the reportability requirements were met and that the commitment to make procedural changes were also met.

See Section 4OA7 for enforcement disposition. No additional findings were identified.

Both versions of this LER as well as the unresolved item are closed.

These activities constitute completion of one event follow-up sample as defined in Inspection Procedure 71153-05.

.2 (Closed) LER 05000482/2010-014-00, Technical Specification Required Shutdown Due

to Inadequate Planning Resulting in Extended Emergency Diesel Generator Inoperability

On December 6, 2010, at 9:48 a.m., CST, Wolf Creek Generating Station entered Mode 3 in accordance with required action H.1 of Technical Specification 3.8.1, "AC Sources - Operating." The required shutdown was due to inoperability of the train A emergency diesel generator which was removed from service on November 29, 2010, for planned maintenance.

The cause of the required shutdown was the inability to return the emergency diesel generator to operable status within the 7-day completion time of required action B.4.2.2 of technical specification 3.8.1. The extended out-of-service time was due to emergent work activities, including a drop in peak firing pressure in one cylinder during the surveillance run of the emergency diesel generator. An adjustment to the injector

linkage corrected the condition. This event is reportable under 10 CFR 50.73(a)(2)(i)(A)and as a completion of a nuclear plant shutdown required by the plants technical specifications. This event was also reported on December 6, 2010, under 10 CFR 50.72(b)(2)(i) as the initiation of a shutdown required by plant technical specifications.

No findings were identified. These activities constitute completion of one event follow-up sample as defined in Inspection Procedure 71153-05.

.3 Closed: LER 2011-005-00, Source Range In-Op on Entry into Mode 6

On April 30, 2011, Wolf Creek Generating Station entered Mode 6 for reloading fuel into the reactor vessel. When the second bundle of fuel was brought in close proximity to nuclear instrumentation source range detector SEN0031, the operators did not observed the expected response from the detector. Refueling operations were suspended to investigate the problem. The inspectors reviewed the LER 2011-005-00 and condition report 38465 to determine the sequence of events. Additionally, the corrective actions were reviewed for appropriateness. LER 2011-005-00 is closed.

A licensee-identified violation is documented in section 4OA7. No additional findings were identified.

These activities constitute completion of one event follow-up sample as defined in Inspection Procedure 71153-05.

.4 Closed: LER 2012-002-00, One Train of Safety Injection Blocked during Entry into Mode

3 due to Procedural Weakness

On March 19, 2012, Wolf Creek Generating Station entered Mode 3 with the train A automatic safety injection actuation signal blocked. Changing from Mode 4 to 3 with an inoperable automatic safety injection actuation signal is prohibited by technical specifications. The inspectors reviewed the LER 2012-002-00 and condition report 50708 to determine the sequence of events. Additionally, the corrective actions were reviewed for appropriateness. This closes LER 2012-002-00.

A licensee-identified violation is documented in section 4OA7. No additional findings were identified.

These activities constitute completion of one event follow-up sample as defined in Inspection Procedure 71153-05.

.

4OA5 Other Activities

.1 (Closed) VIO 05000482/2012007-06, Failure to Implement Corrective Actions to Test

Safety-Related Equipment.

Wolf Creek was issued a notice of cited violation (NOV EA-12-135) on July 5, 2012, as part of the biennial problem identification and resolution inspection report (05000482/2012007). Wolf Creek responded to the violation in a letter dated August 2, 2012, committing to test the equipment in question, the train A essential service water and emergency diesel generator exhaust tornado dampers no later than September 3, 2012. The inspectors reviewed the results of the testing which was performed on August 3, 2012. An as-found failure of the train A emergency diesel generator exhaust damper was further inspected in Section 1R13 of this report. The increased damper break-away torque was later found to not exceed that required to shut the damper in a tornado. The inspectors reviewed that evaluation and found it acceptable.

VIO 05000482/2012007-06 is closed.

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On August 17, 2012, the inspector presented the results of the onsite inspection of the licensees emergency preparedness program to Mr. J. Broschak, Vice President, Engineering, and other members of the licensees staff. The licensee acknowledged the issues presented.

All proprietary materials identified during the inspection were returned to the licensee prior to leaving the site.

On August 30, 2012, the inspectors presented the results of the 50.59/modifications inspection to Mr. J. Broschak, Vice President, Engineering, and other members of the licensees staff. The licensee acknowledged the results as presented. While some proprietary information was reviewed during this inspection, no proprietary information was included in this report.

On September 27, 2012, the inspectors presented the results of the radiation safety inspections to Mr. R. Smith, Site Vice President and Plant Manager, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On October 10, 2012, the resident inspectors presented their inspection results to Mr. R. Smith, Site Vice President, 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.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as a non-cited violation.

.1 On August 2, 2012, the inspectors reviewed a licensee-identified violation of 10 CFR

Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when the turbine-driven auxiliary feedwater pump was found to have excessive oil contamination.

On August 11, 2011, Wolf Creeks oil sampling program received laboratory results for the turbine side of the turbine-driven auxiliary feedwater pump. The oil analysis had high particulates greater than the action level. The oil was filtered and exchanged several times and returned to service. In February 2012, the Terry turbine and governor system was disassembled and cleaned. The electronic governor regulator to pedestal adapter had significant corrosion and was cleaned. Vendor analyses of the electronic governor regulator found that degraded performance and eventual failure was a likely outcome.

The failure to ensure oil quality met industry standards of the turbine-driven auxiliary feedwater governor oil system was a performance deficiency. This finding was more than minor because it impacted the equipment performance attribute of the Mitigating Systems Cornerstone and affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, and found that a detailed risk evaluation was required because the performance deficiency caused one train to be out of service for greater than its technical specification allowed outage time.

The senior reactor analyst estimated the risk of potential increase in pump failure probability caused by the degraded oil conditions. The overall risk of the performance deficiency would increase as the estimated failure probability increased and decrease as the estimated time the pump would run before failure increased. After reviewing the range of risk values over the spectrum of pump performance, Region IV management determined that the significance of the performance deficiency was very low (Green), in accordance with Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. 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, procedures, or drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.

Procedure I-ENG-004, Lubricating Oil Analysis, Revision 3, step 1.1 specified, in part, that oil analysis be performed to detect degrading oil and component conditions.

Procedure I-ENG-004, Attachment A, specified quality standards for water and particulates. Contrary to the above, from September 9, 2010, to August 11, 2011, oil analysis failed to identify degrading turbine oil below acceptable limits because water and particulate analyses were not consistently specified or acted upon when limits were exceeded. The licensee has entered this into the corrective action program as condition report 42635.

.2 On April 30, 2011, Wolf Creek identified a non-cited violation of Technical

Specifications 3.0.4 and 3.9.3 for entry into Mode 6 with an inoperable source range neutron detector. On April 30, 2011, operators channel checked the nuclear instrumentation source range detectors SEN0031 and SEN0032 count rate using procedure STS CR-002. On April 30, 2011, Mode 6 was entered from defueled condition. At that time operators believed that both source range detectors were operable. When a bundle of fuel was brought in close proximity to source range detector SEN0031, the operators did not observe the expected response from the detector. Refueling operations were suspended, the detector declared inoperable and the problem investigated. A pulse shaper circuit card was found failed and replaced.

Failure to maintain two operable source range detectors prior to entering Mode 6 from a defueled condition was a performance deficiency. Wolf Creek has since changed its procedures to use the plant computer to trend source range indications for channel checks prior to entering Mode 6. The performance deficiency was more than minor because it impacted the Mitigating Systems Cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The significance of the finding was determined using Inspection Manual Chapter 0609, Significance Determination Process, Appendix G, checklist 3, and determined to be of very low safety significance (Green), because it did not cause the loss of mitigating capability of core heat removal, inventory control, power availability, containment control, or reactivity control. Wolf Creek Generating Stations Technical Specification 3.0.4 requires, in part, entry into a Mode shall only be made when the limiting conditions of operation be met prior to changing modes. Technical Specification 3.9.3 requires, in part, that both source range nuclear instruments be operable in Mode 6. Contrary to the above, on April 30, 2011, Wolf Creek entered Mode 6 with one source range instrument inoperable. Since the finding is of very low safety significance, was identified by Wolf Creek, and has been entered into the licensees corrective action program as condition report 38465, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy.

.3 A Green licensee-identified non-cited violation of Technical Specification 3.3.2,

Table 3.3.2-1, function 1.b, for entry into Mode 3 with one train of automatic safety injection actuation operable. In March 2012, while in Mode 5, a portion of procedure STS KJ-001A, "Integrated D/G and Safeguards Actuation Test - Train A," was performed as a required retest for maintenance conducted on the train A emergency diesel generator. After the testing was completed, both safety injection manual reset buttons for train A and B were depressed. Due to the reactor trip breakers being open, the automatic safety injection block status window was still lit. Prior to entry into Mode 4, both trains of solid state protection system were enabled, which reset the actuation logic and relays. But since this was a forced outage and not a refueling outage, performance of procedure STS RE-017, DRPI (Digital Rod Position Indication) Operability Verification, was not required and the reactor trip breakers were not closed, allowing the resetting of the auto safety injection block by closing reactor trip breakers. Failure to maintain an operable safety injection train A prior to entering Mode 3 from Mode 4 was a performance deficiency. The performance deficiency was more than minor because it

impacted the Mitigating Systems Cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The significance of the finding was determined using Inspection Manual Chapter 0609, Significance Determination Process, Appendix G, checklist 4, and determined to be of very low safety significance (Green), because it did not cause the loss of mitigating capability of core heat removal, inventory control, power availability, containment control, or reactivity control. Wolf Creek Generating Station Technical Specification 3.3.2, Table 3.3.2-1, function 1.b, requires two trains of automatic safety injection actuation logic in Mode 3. Contrary to the above, on March 19, 2012, Wolf Creek entered Mode 3 with one train of automatic safety injection actuation inoperable.

Since the finding is of very low safety significance, was identified by Wolf Creek, and has been entered into the licensees corrective action program as condition report 50708, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy.

.4 Title 10 CFR Part 20.1501(a) requires that each licensee shall make or cause to be

made, surveys that describe magnitude and extent of potential radiation hazards.

Contrary to this requirement, on November 22, 2011, the licensee identified a failure to perform adequate surveys to verify radiological conditions within the auxiliary building when a dose rate alarm occurred from an area radiation monitor (ARM) spike. The ARM is located in the southeast corner of room 1203 in the pipe chase of the 1988 foot elevation of the auxiliary building. A health physics technician was sent to investigate the alarm and survey the area. The technician found a pipe with contact dose rates of 260 mrem per hour and 100 mrem per hour at 30 cm. The general area dose rate met the requirement of a high radiation area. A second health physics technician verified the dose rates. The technicians received approval to post the area as a high radiation area.

A couple of hours later, a third health physics technician was requested to survey the same area by the on-call health physics supervisor. The third health physics technician determined that the dose rates did not meet the requirements of a high radiation area, with the maximum dose rate less than 100 mrem per hour at 30 cm, and requested that the area be down posted to a radiation area. Without a verification of the survey, the on-call supervisor approved the down post to a radiation area. Upon further survey verification on November 27, 2011, it was determined that the dose rates identified by the third technician were incorrect and the area was, in fact, a high radiation area. Thus, from November 22 to 27, 2011, the area was characterized as an unposted high radiation area due to a failure to properly survey. This issue was documented in the licensees corrective action program as condition report 00046303. Using the Occupational Radiation Safety Significance Determination Process, the inspectors determined the finding had very low safety significance (Green) because:

(1) it was not an as low as is reasonably achievable finding,

(2) there was no overexposure,

(3) there was no substantial potential for an overexposure, and

(4) the ability to assess dose was not compromised. There is no crosscutting component because this is a licensee-identified finding.

.5 Technical Specification Section 5.7.1.a requires, in part, that each entryway to high

radiation areas not exceeding 1.0 rem per hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation shall be barricaded and conspicuously posted as a high radiation area. Contrary to this requirement, on September 11, 2012, the licensee was performing a routine review of surveys and identified that an area in the pipe chase of the 1988 foot elevation of the auxiliary building was an unposted high radiation area. Survey WCNOC-1209-0092, dated September 7, 2012, documented dose rates of 250 mrem per hour on contact and 120 mrem per hour at 30 cm, but only showed a level 1 posting, which is characterized as a radiation area. Thus, on September 11, 2012, a health physics technician was sent to verify the dose rates and posting as documented by the survey. The technician determined the maximum dose rates to be 220 mrem per hour on contact and 100 mrem per hour at 30 cm. These readings were documented in survey WCNOC-1209-0148.

The area was immediately barricaded and conspicuously posted as a high radiation area. This issue was documented in the licensees corrective action program as condition report 00057185. Using the Occupational Radiation Safety Significance Determination Process, the inspectors determined the finding had very low safety significance (Green) because:

(1) it was not an ALARA finding,

(2) there was no overexposure,

(3) there was no substantial potential for an overexposure, and

(4) the ability to assess dose was not compromised. There is no crosscutting component because this is a licensee-identified finding.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

P. Bedgood, Manager, Radiation Protection

J. Broschak, Vice President, Engineering

R. Clemons, Vice President, Strategic Projects

J. Cuffe, Supervisor, Radiation Protection

D. Dees, Superintendant, Operations

T. East, Superintendent, Emergency Planning

R. Evenson, Requalification Program Supervisor

R. Flannigan, Manager, Nuclear Engineering

K. Fredrickson, Engineer, Licensing

R. Hammond, Supervisor, Regulatory Support

J. Harris, System Engineer

S. Henry, Operations Manager

R. Hobby, Licensing Engineer

S. Hossain, Engineer, System Engineering

A. Jamar, Supervisor Engineer, Electrical Design Engineering

T. Jensen, Manager, Chemistry

J. Keim, Support Engineering Supervisor

M. Legresley, System Engineer

M. McMullen, Technician, Engineering

C. Medici, Supervisor, Radiation Protection

W. Muilenburg, Licensing Engineer

M. McMullen, Design Engineer, Engineering

K. Miller, Technician Level III, Instruments and Controls

R. Murray, Simulator Supervisor

E. Ray, Manager, Training

L. Ratzlaff, Manager, Maintenance

L. Rockers, Licensing Engineer

R. Ruman, Manager, Quality

G. Sen, Regulatory Affairs Manager

D. Scrogum, Systems Engineer, Engineering

M. Skiles, Supervisor, Radiation Protection

R. Smith, Site Vice President

L. Solorio, Senior Engineer

R. Stumbaugh, Health Physicist III, Radiation Protection

M. Sunseri, President and Chief Executive Officer

J. Suter, Supervisor Engineer, Fire Protection

J. Truelove, Supervisor, Chemistry

M. Westman, Assistant to Site Vice President

J. Yunk, Manager, Corrective Actions

NRC Personnel

C. Long, Senior Resident Inspector

C. Peabody, Resident Inspector

L. Ricketson, Senior Health Physicist

N. Green, Health Physicist

R. Kopriva, Senior Reactor Inspector

J. Watkins, Reactor Inspector

C. Speer, Reactor Inspector

G. Guerra, Emergency Preparedness Inspector

S. Hedger, Operations Engineer

N. Makris, Project Engineer

J. Laughlin, Emergency Preparedness Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000482/2012004-01 URI Determine Licensing Basis and Capability of One Vital Air Conditioning Unit to Cool Both Trains of Class IE Electrical Equipment (Section 1R04.2)

Opened and Closed

05000482/2012004-02 NCV Inadequate Operability Evaluation for a Degraded Switchgear Cooling Fan (Section 1R15)

05000482/2012004-03 NCV Safety-Related Fan Flow Rate Acceptance Criteria Reduced Below Design Basis Limit (Section 1R22)

05000482/2012004-04 NCV Failure to Follow Radiation Protection Procedures (Section 1RS01)

05000482/2012004-05 NCV Failure to Follow ALARA Planning Procedures (Section 2RS02)

Closed

05000482/2012007-06 VIO Failure to Implement Corrective Actions to Test Safety-Related Equipment (Section 4OA5.1)

05000482/2011-004-04 URI Excessive Oil Contamination for Turbine-Driven Auxiliary Feedwater Pump (Section 4OA3.1)

05000482/2011-009-00,

LER Inadequate Oil Analysis Caused Inoperable Auxiliary Feedwater Pump Longer Than Required Action Completion Time (Section 4OA3.1)

05000482/2010014-00 LER Technical Specification Required Shutdown Due to Inadequate Planning Resulting in Extended Emergency Diesel Generator Inoperability (Section 4OA3.2)

Closed

05000482/2011-005-00 LER Source Range In-Op on Entry into Mode 6 (Section 4OA3.3)

05000482/2012-002-00 LER One Train of SI blocked during Entry into Mode 3 due to Procedural Weakness (Section 4OA3.4)