IR 05000482/2016002

NRC Integrated Inspection Report 05000482/2016002

ML16218A501
Person / Time
Site:	Wolf Creek
Issue date:	08/03/2016
From:	Nick Taylor NRC Region 4
To:	Heflin A Wolf Creek
nick taylor
References
IR 2016002
Download: ML16218A501 (68)

Text

UNITED STATES ust 3, 2016

SUBJECT:

WOLF CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000482/2016002

Dear Mr. Heflin:

On June 30, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Wolf Creek Generating Station. On July 27, 2016, the NRC inspectors discussed the results of this inspection with Cleveland Reasoner, Site Vice President, and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented one finding of very low safety significance (Green) in this report.

This finding involved a violation of NRC requirements. Further, inspectors documented five licensee identified violations, which were determined to be of very low safety significance in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violations or significance of 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Wolf Creek Generating Station.

If you disagree with a cross-cutting 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 the Wolf Creek Generating Station.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents 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/

Nicholas H. Taylor, Branch Chief Project Branch B Division of Reactor Projects Docket No.: 50-482 License No.: NPF-42

Enclosure:

Inspection Report 05000482/2016002 w/ Attachments:

1. Supplemental Information 2. Request for Information for the O

REGION IV==

Docket: 05000482 License: NPF-42 Report: 05000482/2016002 Licensee: Wolf Creek Nuclear Operating Corporation Facility: Wolf Creek Generating Station Location: 1550 Oxen Lane NE Burlington, KS 66839 Dates: April 1 through June 30, 2016 Inspectors: D. Dodson, Senior Resident Inspector F. Thomas, Resident Inspector L. Carson II, Senior Health Physicist J. Drake, Senior Reactor Inspector N. Greene, PhD, Health Physicist P. Hernandez, Health Physicist M. Phalen, Senior Health Physicist D. Proulx, Senior Project Engineer W. Sifre, Senior Reactor Inspector C. Stott, Reactor Inspector Approved Nicholas H. Taylor By: Chief, Project Branch B Division of Reactor Projects-1- Enclosure 1

SUMMARY

IR 05000482/2016002; 04/01/2016 - 06/30/2016; Wolf Creek Generating Station; Follow-up of

Events and Notices of Enforcement The inspection activities described in this report were performed between April 1 and June 30, 2016, by the resident inspectors at Wolf Creek Generating Station and inspectors from the NRCs Region IV office. One finding of very low safety significance (Green) is documented in this report. This finding involved a violation of NRC requirements. Additionally, NRC inspectors documented in this report five licensee-identified violations of very low safety significance. The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red),

which is determined using Inspection Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310,

Aspects within the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green non-cited violation of Technical Specification Limiting Condition for Operation 3.7.11 and 3.0.3 for the licensees failure to place the unit in mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, and mode 5 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> with two trains (SGK04A and SGK04B) of the control room air conditioning system (CRACS)inoperable. Specifically, the licensee failed to adequately establish CRACS testing flow rate acceptance criteria, which resulted in train A of the safety-related CRACS being inoperable from October 11, 2005, to August 13, 2013; and train B being inoperable from October 3, 2002, to July 18, 2013. The licensees immediate corrective actions included corrective maintenance on the CRACS to increase the airflow to meet acceptance criteria limits. Condition Report 105208 was initiated by the licensee for any necessary process changes and extent of condition actions.

This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors utilized Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Exhibit 2 of Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and determined this finding was not a deficiency affecting the design or qualification of a mitigating SSC that maintained its operability or functionality, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of function of at least a single train for greater than its Technical Specification allowed outage time, and the finding did not represent an actual loss of function of one or more non-Technical Specification trains of equipment designated as high safety-significant. Therefore, the inspectors determined the finding was of very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance, change management, because leaders did not use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority. Specifically, there is not currently a formal process for procedure writers to consider measurement uncertainty when establishing and changing testing acceptance criteria, which resulted in extended inoperability of both the SGK04A and SGK04B units following significant changes to Technical Specifications that included adding surveillance requirements for the SGK04A and SGK04B units in 1999. This issue is indicative of current performance because the same issue would be expected to occur today [H.3]. (Section 4OA3)

Licensee-Identified Violations

Five violations of very low safety significance 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.

PLANT STATUS

Wolf Creek Generating Station operated at or near full power for the entire inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

On April 26, 2016, the inspectors completed an inspection of the stations readiness for impending adverse weather conditions. The inspectors reviewed plant design features, the licensees procedures to respond to severe thunderstorms and tornado watches, and the licensees planned implementation of these procedures. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant.

These activities constituted one sample of readiness for impending adverse weather conditions, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial Walk-Down

a. Inspection Scope

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

• April 28, 2016, control room air conditioning unit B

• May 18, 2016, component cooling water pump B

• May 25, 2016, emergency diesel generator B

• June 7, 2016, component cooling water pump D The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. They visually verified that critical portions of the systems were correctly aligned for the existing plant configuration.

These activities constituted four partial system walk-down samples as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Inspection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on four plant areas important to safety:

• May 25, 2016, fire area F-1, general floor area, elevation 2047 feet

• May 31, 2016, fire area A-15, auxiliary feedwater pump room C, elevation 2000 feet

• June 17, 2016, fire area A-27, motor generator set room, elevation 2026 feet

• June 29, 2016, fire area ESW-1, essential service water pump house A train, elevation 2000 feet For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.

These activities constituted four quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

.2 Annual Inspection

a. Inspection Scope

On June 24, 2015, the inspectors completed their annual evaluation of the licensees fire brigade performance. This evaluation included observation of an unannounced fire drill for a fire in the north end of the auxiliary building, elevation 1974 feet (A-1), on June 24, 2016.

During this drill, the inspectors evaluated the capability of the fire brigade members, the leadership ability of the brigade leader, the brigades use of turnout gear and fire-fighting equipment, and the effectiveness of the fire brigades team operation. The inspectors also reviewed whether the licensees fire brigade met NRC requirements for training, dedicated size and membership, and equipment.

These activities constituted one annual inspection sample, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

.1 Annual Review

a. Inspection Scope

On April 5, 2016, the inspectors completed an inspection of the readiness and availability of risk-significant heat exchangers. The inspectors observed the licensees inspection of the SGK04B control room air-conditioning unit heat exchanger and the material condition of the heat exchanger internals. Additionally, the inspectors walked down the SGK04B heat exchanger to observe its performance and material condition and verified that the SGK04B heat exchanger was correctly categorized under the Maintenance Rule and was receiving the required maintenance.

These activities constituted completion of one heat sink performance annual review sample, as defined in Inspection Procedure 71111.07.

b. Findings

No findings were identified.

.2 Triennial Review

a. Inspection Scope

On May 23, 2016, through May 26, 2016, the inspectors completed an inspection of the readiness and availability of risk-significant heat exchangers. The inspectors reviewed licensee programs to verify heat exchanger performance and operability for the following heat exchangers:

• Component cooling water heat exchanger A

• Containment air cooler A

• Air compressor and aftercooler B

• Fuel pool cooling pump room cooler B

• Class 1E switchgear cooler A The inspectors verified whether testing, inspection, maintenance, and chemistry control programs are adequate to ensure proper heat transfer. The inspectors verified that the periodic testing and monitoring methods, as outlined in commitments to NRC Generic Letter 89-13, utilized proper industry heat exchanger guidance. Additionally, the inspectors verified that the licensees chemistry program ensured that biological fouling was properly controlled between tests. The inspectors reviewed previous maintenance records of the heat exchangers to verify that the licensees heat exchanger inspections adequately addressed structural integrity and cleanliness of their tubes.

These activities constitute completion of five triennial heat sink inspection samples as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

a. Inspection Scope

This inspection was focused on closing an Unresolved Item (URI) opened during the performance of Inspection Procedure 71111.08, Inservice Inspection Activities, documented in NRC Inspection Report 05000482/2015001. The inspectors reviewed additional licensing basis information provided by the licensee, as well as industry standards and regulatory guidance. Information in Section 4OA5 of this report documents the resolution of this URI.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On May 16, 2014, the inspectors observed an evaluated simulator scenario performed by an operating crew. The inspectors assessed the performance of the operators and the evaluators critique of their performance. The inspectors also assessed the modeling and performance of the simulator during the requalification activities.

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

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

On June 1, 2016, 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 risk due to the ongoing performance of STS IC-508A, Refueling Water Storage Tank Level Transmitter Calibration, Revision 6; during two previous performances of the same procedure on May 19 and 26, 2016, the station received a reactor partial trip alarm concurrent with a low steam line pressure bistable trip.

In addition, the inspectors assessed the operators adherence to plant procedures, including the conduct of operations procedure and other operations department policies.

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

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed one instance of degraded performance or condition of safety-related structures, systems, and components (SSCs):

• March 10, 2016, SKG04A and SGK04B control room air conditioning units, refrigerant leaks The inspectors reviewed the extent of condition of possible common cause SSC failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the SSCs. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.

These activities constituted completion of one maintenance effectiveness sample, as defined in Inspection Procedure 71111.12.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed two risk assessments performed by the licensee prior to changes in plant configuration and the risk management actions taken by the licensee in response to elevated risk:

• April 28, 2106, planned maintenance on control room air conditioning unit A

• May 25, 2016, planned maintenance outages for emergency diesel generator A and essential service water system A The inspectors verified that these risk assessments were performed timely and in accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant procedures. The inspectors reviewed the accuracy and completeness of the licensees risk assessments and verified that the licensee implemented appropriate risk management actions based on the results of the assessments.

The inspectors also observed portions of two emergent work activities that had the potential to cause an initiating event and to affect the functional capability of mitigating systems:

• April 12, 2016, repair of Benton 345 kilovolt offsite power line support structure

• May 23, 2016, maintenance on emergency diesel generator A channel 1 undervoltage bistable power supply The inspectors verified that the licensee appropriately developed and followed a work plan for these activities. The inspectors verified that the licensee took precautions to minimize the impact of the work activities on unaffected SSCs.

These activities constituted completion of four maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed three operability determinations and functionality assessments that the licensee performed for degraded or nonconforming SSCs:

• April 25, 2016, operability determination of essential service water pump discharge check valves and cross-connect check valves

• May 5, 2016, operability determination of essential service water pump B discharge check valve

• June 7, 2016, functionality determination of diesel fire pump The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable or functional, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability or functionality. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability or functionality of the degraded SSC.

These activities constituted completion of three operability and functionality review samples as defined in Inspection Procedure 71111.15.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed five post-maintenance testing activities that affected risk-significant SSCs:

• April 6, 2016, SGK04B control room air conditioning unit

• April 21, 2016, shutdown rod bank E demand counter

• May 3, 2016, emergency diesel generator B emergency fuel oil storage tank level indicator replacement

• May 19, 2016, steam line low pressure bistable card replacement

• May 31, 2016, turbine driven auxiliary feedwater pump test The inspectors reviewed licensing- and design-basis documents for the SSCs and the maintenance and post-maintenance test procedures. The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected SSCs.

These activities constituted completion of five post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed six risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the SSCs were capable of performing their safety functions:

In-service tests:

• May 5, 2016, STS EF-100B, [Essential Service Water] System Inservice Pump B

& [Essential Service Water] B Check Valve Test, Revision 47

• June 1, 2016, STS AL-201C, Turbine Driven Auxiliary Feedwater System Inservice Valve Test, Revision 9 Containment isolation valve surveillance tests:

• April 11, 2016, STS BM-205, "[Steam Generator Blowdown] System Inservice Valve Test, Revision 13 Reactor coolant system leak detection tests:

• May 4, 2016, STS BB-006, [Reactor Coolant System] Water Inventory Balance Using the NPIS Computer, Revision 14 Other surveillance tests:

• April 7, 2016, STS GG-001B, Emergency Exhaust Filtration System Train B Operability Test, Revision 23

• May 12, 2016, STS IC-255B, Channel Operational Test Control Room Air Intake Radiation Monitor, Revision 16A The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the test satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected SSCs following testing.

These activities constituted completion of six surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors evaluated the accuracy and operability of the radiation monitoring equipment used by the licensee to monitor areas, materials, and workers to ensure a radiologically safe work environment. This evaluation included equipment used to monitor radiological conditions related to normal plant operations, anticipated operational occurrences, and conditions resulting from postulated accidents. The inspectors interviewed licensee personnel, walked down various portions of the plant, and reviewed licensee performance associated with radiation monitoring instrumentation, as described below:

• The inspectors performed walk downs and observations of selected plant radiation monitoring equipment and instrumentation, including portable survey instruments, area radiation monitors, continuous air monitors, personnel contamination monitors, portal monitors, and small article monitors. The inspectors assessed material condition and operability, evaluated positioning of instruments relative to the radiation sources or areas they were intended to monitor, and verified performance of source checks and calibrations.

• The inspectors evaluated the calibration and testing program, including laboratory instrumentation, whole body counters, post-accident monitoring instrumentation, portal monitors, personnel contamination monitors, small article monitors, portable survey instruments, area radiation monitors, electronic dosimetry, air samplers, and continuous air monitors.

• The inspectors assessed problem identification and resolution for radiation monitoring instrumentation. The inspectors reviewed audits, self-assessments, and corrective action program documents to verify problems were being identified and properly addressed for resolution.

These activities constituted completion of the three required samples of radiation monitoring instrumentation, as defined in Inspection Procedure 71124.05.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

The inspectors evaluated whether the licensee maintained gaseous and liquid effluent processing systems and properly mitigated, monitored, and evaluated radiological discharges with respect to public exposure. The inspectors verified that abnormal radioactive gaseous or liquid discharges and conditions, when effluent radiation monitors are out-of-service, were controlled in accordance with the applicable regulatory requirements and licensee procedures. The inspectors verified that the licensees quality control program ensured radioactive effluent sampling and analysis adequately quantified and evaluated discharges of radioactive materials. The inspectors verified the adequacy of public dose projections resulting from radioactive effluent discharges. The inspectors interviewed licensee personnel and reviewed licensee performance in the following areas:

• During walk downs and observations of selected portions of the radioactive gaseous and liquid effluent equipment, the inspectors evaluated routine processing and discharge of effluents, including sample collection and analysis.

The inspectors observed equipment configuration and flow paths of selected gaseous and liquid discharge system components, effluent monitoring systems, filtered ventilation system material condition, and significant changes to effluent release points.

• Calibration and testing program for process and effluent monitors, including National Institute of Standards and Technology (NIST) traceability of sources, primary and secondary calibration data, channel calibrations, set-point determination bases, and surveillance test results.

• Sampling and analysis controls used to ensure representative sampling and appropriate compensatory sampling. Reviews included results of the inter-laboratory comparison program.

• Instrumentation and equipment, including effluent flow measuring instruments, air cleaning systems, and post-accident effluent monitoring instruments.

• Dose calculations for effluent releases. The inspectors reviewed a selection of radioactive liquid and gaseous waste discharge permits and abnormal gaseous or liquid tank discharges, and verified the projected doses were accurate. The inspectors also reviewed 10 CFR Part 61 analyses and methods used to determine which isotopes were included in the source term. The inspectors reviewed land use census results, offsite dose calculation manual changes, and significant changes in reported dose values from previous years.

• Problem identification and resolution for radioactive gaseous and liquid effluent treatment. The inspectors reviewed audits, self-assessments, and corrective action program documents to verify problems were being identified and properly addressed for resolution.

These activities constituted completion of the six required samples of radioactive gaseous and liquid effluent treatment program, as defined in Inspection Procedure 71124.06.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program

a. Inspection Scope

The inspectors evaluated whether the licensees radiological environmental monitoring program quantified the impact of radioactive effluent releases to the environment and sufficiently validated the integrity of the radioactive gaseous and liquid effluent release program. The inspectors also verified that the licensee continued to implement the voluntary Nuclear Energy Institute/Industry Ground Water Protection Initiative. The inspectors reviewed or observed the following items:

• The inspectors observed selected air sampling and dosimeter monitoring stations, sampler station modifications, and the collection and preparation of environmental samples. The inspectors reviewed calibration and maintenance records for selected air samplers, composite water samplers, and environmental sample radiation measurement instrumentation, and inter-laboratory comparison program results. The inspectors reviewed selected events documented in the annual environmental monitoring report and significant changes made by the licensee to the offsite dose calculation manual as the result of changes to the land census. The inspectors evaluated the operability, calibration, and maintenance of meteorological instruments and assessed the meteorological dispersion and deposition factors. The inspectors verified the licensee had implemented a sampling and monitoring program sufficient to detect leakage from SSCs with credible mechanism for licensed material to reach ground water and reviewed changes to the licensees written program for identifying and controlling contaminated spills/leaks to groundwater.

• Groundwater protection initiative implementation, including assessment of groundwater monitoring results, identified leakage or spill events and entries made into 10 CFR 50.75(g) records, licensee evaluations of the extent of the contamination and the radiological source term, and reports of events associated with spills, leaks, and groundwater monitoring results.

• Problem identification and resolution for the radiological environmental monitoring program. The inspectors reviewed audits, self-assessments, and corrective action program documents to verify problems were being identified and properly addressed for resolution.

These activities constituted completion of the three required samples of radiological environmental monitoring program, as defined in Inspection Procedure 71124.07.

b. Findings

No findings were identified.

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage,

and Transportation (71124.08)

a. Inspection Scope

The inspectors evaluated the effectiveness of the licensees programs for processing, handling, storage, and transportation of radioactive material. The inspectors interviewed licensee personnel and reviewed the following items:

• Radioactive material storage waste storage areas including container labeling/marking and monitoring containers for deformation or signs of waste decomposition.

• Radioactive waste system walk-down including radioactive waste processing and handling equipment. Review of waste processing equipment that is not operational or abandoned in place equipment consistent with system descriptions and the process control program.

• Waste characterization and classification including radio-chemical sample analysis results for radioactive waste streams and use of scaling factors and calculations to account for difficult-to-measure radionuclides, processes for waste classification including use of scaling factors and 10 CFR Part 61 analysis.

• Shipment preparation packaging, surveying, labeling, marking, placarding, vehicle checking, driver instructing, and preparation of the disposal manifests.

• Shipping records including for LSAI, II, III; SCOI, II: Type A or Type B records.

• Problem identification and resolution for radioactive solid waste processing and radioactive material handling, storage, and transportation. The inspectors reviewed audits, self-assessments, and corrective action program documents to verify problems were being identified and properly addressed for resolution.

These activities constituted completion of the six required samples of radioactive solid waste processing and radioactive material handling, storage, and transportation program, as defined in Inspection Procedure 71124.08.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors reviewed the licensees reactor coolant system chemistry sample analyses for the period of April 1, 2015, through March 31, 2016, to verify the accuracy and completeness of the reported data. The inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample on June 13, 2016. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the reactor coolant system specific activity performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Reactor Coolant System Identified Leakage (BI02)

a. Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system identified leakage for the period of April 1, 2015, through March 31, 2016, to verify the accuracy and completeness of the reported data. The inspectors observed the performance of STS BB-006, RCS Water Inventory Balance Using the NPSI Computer, Revision 14, on June 24, 2016. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the reactor coolant system leakage performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Semiannual Trend Review

a. Inspection Scope

The inspectors reviewed the licensees corrective action program, performance indicators, station performance reports, and other documentation to identify trends that might indicate the existence of a more significant safety issue. The inspectors verified that the licensee was taking corrective actions to address the following identified adverse trends:

• Procedure use and adherence

• Operability evaluations These activities constituted completion of one semiannual trend review sample, as defined in Inspection Procedure 71152.

b. Observations and Assessments The inspectors evaluated a sample of issues and events that occurred over the course of the past two quarters to determine whether issues were appropriately considered as emerging or adverse trends. The inspectors verified that these issues were addressed within the scope of the corrective action program or through department review and documentation in the quarterly trend presentation for overall assessment.

The inspectors identified issues associated with implementation of Procedure AP 15C-002, Procedure Use and Adherence:

• The inspectors identified six separate issues associated with implementation of Procedure AP 15C-002, Procedure Use and Adherence, Revision 41, during one test. Section 6.1.2, for continuous use procedures, states, Review and placekeep each step after completion to ensure the step was performed correctly, and Each step of a continuous use procedure shall be completed or properly N/Ad before proceeding to the next step. On May 5, 2016, the inspectors observed activities associated with completion of Procedure STS EF-100B, [Essential Service Water] System Inservice Pump B & [Essential Service Water] B Check Valve Test, Revision 47, and noted six separate issues associated with the licensee reviewing and placekeeping each step after completion to ensure the step was performed correctly, and the licensee ensuring each step of the continuous use procedure was completed or properly N/Ad before proceeding to the next step. Specifically, Step 8.2.3.3 was inappropriately marked as N/A; Steps 8.2.23.3 and 8.2.23.4 were not performed correctly due to transposition and recording errors; Step 8.2.24.1 utilized an incorrect pressure value; and Step 8.1.17 data was recorded with a unit error. None of these six separate issues were identified by the implementing operations crew or during the operations crew review of the procedure. These issues were entered into the corrective action program as Condition Report 104532.

• The inspectors identified that Procedure AP 15C-002, Procedure Use and Adherence, Revision 41, Section 6.1.2, for continuous use procedures, states, Perform the step as written in the sequence specified, except when the procedure or approved process specifically allows deviation. On June 1, 2016, the inspectors observed activities associated with completion of Procedure STS IC-508A, Refueling Water Storage Tank Level Transmitter Calibration, Revision 6, and noted that steps were not performed as written in the sequence specified, and the approved process did not specifically allow deviation.

Specifically, personnel did not recognize the need to document supervisor approval to re-perform an as-found data collection step. This issue was entered into the corrective action program as Condition Report 105566.

The inspectors discussed the issues associated with following Procedure AP 15C-002, Procedure Use and Adherence, at the exit meeting on July 27, 2016. The licensee documented Condition Report 106079 in response to the inspectors observations.

The inspectors noted that NRC Inspection Report 05000482/2015004 documented an apparent increase in the number of operability evaluation issues. The inspectors observed apparent station improvement in this area as a result of actions associated with Condition Report 96033, increased control room oversight, and periodic operability determination training. Although operability process implementation improvement was recognized by the inspectors, the inspectors noted some continuing NRC-identified issues. Specifically, these included:

• The inspectors identified that Procedure AP 26C-004, Determination and Functionality Assessment, Revision 32, states that operability determinations should include whether there is a reasonable expectation of operability, including the basis for the determination and any compensatory measures put in place to establish or restore operability. This procedure was not adequately implemented on two occasions in response to Condition Reports 104268 and 104066. Neither Condition Report 104268 nor Condition Report 104066 adequately addressed operability concerns associated with the emergency diesel generator fuel oil transfer pump control circuitrys potential to activate the thermal overloads that would stop the pump and render the emergency diesel generator inoperable; NCV 05000482/2016007-02, Failure to Verify the Adequacy of Design of the Control Circuitry of the Fuel Oil Transfer Pumps, documents additional details concerning the technical issue. Specifically, the immediate operability screening for both conditions reports was determined to be, N/A, and failed to evaluate the issue for immediate operability. Although an immediate operability determination was not immediately completed, the licensee revised its operability screening, completed an immediate operability determination, and adequately justified operability. This issue was entered into the corrective action program as Condition Report 104322.

• The licensee identified that the operability determination associated with Condition Report 104910 was inadequately completed. Specifically, a negative trend in B component cooling water pump outboard bearing oil leakage rate was identified, and the operability determination did not quantify the leakage rate and compare that to the mission time specified in AP 26C-004, Operability Screening, Revision 32. After additional information from engineering was received and quantification of the oil leakage rate was completed, the operability determination was changed to Inoperable. A licensee identified violation documented in Section 4OA7 of this report discusses this issue.

• The inspectors identified that operability evaluations were not always completed in a timely manner while additional information was being gathered to justify operability. Specifically, completion of operability evaluations associated with the 2016 Component Design Basis team inspection and issues associated with resident inspector activities were sometimes delayed to prevent burdening Operations with unanswered questions during operability screenings. Also, operability determinations for issues associated with resident inspector activities and questions were apparently delayed while additional analyses were performed to justify operability. Specifically, following inspector questions that identified issues associated with a penetration into a safety related area, an operability determination and condition report appeared to be delayed to facilitate completion of analysis that could be used to justify operability. Condition Report 105307 documented the inspectors concerns.

The inspectors discussed the continuing operability process issues at the exit meeting on July 27, 2016. The licensee documented Condition Report 106062 to address continuing operability process issues.

c. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report (LER) 05000482/2014-001-00: Failure to Comply with

Required Action of Technical Specification 3.4.3 while Performing a Vacuum Fill of the Reactor Coolant System During a review of outside operating experience on January 6, 2014, the licensee determined that the reactor coolant system pressure was placed in a vacuum condition, in violation of Technical Specification 3.4.3, which specifies a minimum operating pressure of 0 psig. Wolf Creek operators drew a vacuum on the reactor coolant system to support reactor coolant system filling operations on May 8, 2011, and March 30, 2013, using Procedure SYS BB-112, Vacuum Fill of the RCS (to approximately 20 inches of Hg, absolute pressure). Technical Specification 3.4.3, [Reactor Coolant System]

Pressure and Temperature Limits, requires, in part, that the licensee maintain the reactor coolant system pressure, temperature, and heatup and cooldown rates to the limits specified in the Pressure and Temperature Limits Report (PTLR) at all times. The limits of the curves in the PTLR specify a minimum pressure of 0 psig. Required Action C.1 of Technical Specification 3.4.3 specifies that with the reactor coolant system parameters outside of the limits of the PTLR, restore the parameters to within the limits immediately. Because the plant was outside of the PTLR limits with respect to pressure and not restored immediately, the plant was in a condition prohibited by the Technical Specifications, which is reportable pursuant to 10 CFR 50.73(a)(2)(i)(B).

The licensee placed this issue in the corrective action program as Condition Report 78920. For immediate corrective actions, the licensee cancelled the procedure that implemented vacuum fill of the reactor coolant system. The inspectors determined that this constituted a licensee-identified violation, and the enforcement aspects of this violation are discussed in Section 4OA7 of this inspection report.

This licensee event report is closed.

.2 (Closed) LER 05000482/2014-004-00: Condition Prohibited by Technical Specifications

due to an Instrument Tunnel Sump Level Indication Transmitter Incompatible with the Containment Environment On June 2, 2014, the licensee determined that the instrument tunnel sump level indication was inoperable from the period of July 13, 2013, to November 20, 2013, due to erratic and unreliable indication. Therefore, the required actions of Technical Specification 3.4.15 [Reactor Coolant System] Leakage Detection Instrumentation,"

were not met. Because the licensee did not take the required actions of Technical Specification 3.4.15, the plant was in a condition prohibited by the Technical Specifications, which is reportable pursuant to 10 CFR 50.73(a)(2)(i)(B). The licensees root cause analysis determined that the local transmitter was not qualified for the long term exposure of the radiation levels encountered in containment, resulting in the erratic indication.

The licensee placed this issue in the corrective action program as Condition Report 84690. For immediate corrective actions, the licensee instituted compensatory measures for alternate means of identifying reactor coolant system leakage. In April 2015, the licensee replaced the instrument tunnel sump transmitter with two newly designed and fully qualified transmitters, and tested them satisfactorily. The inspectors reviewed the licensees corrective action documents and determined the actions had been completed. The inspectors determined that this constituted a licensee-identified violation, and the enforcement aspects of this violation are discussed in Section 4OA7 of this inspection report.

This licensee event report is closed.

.3 (Closed) LER 05000482/2015-002-00: Two Control Room Air Conditioning Trains

Inoperable Due to Failure to Meet Surveillance Requirement, and LER 05000482/2015-002-01: Two Control Room Air Conditioning Trains Inoperable Due to Failure to Meet Surveillance Requirement

a. Inspection Scope

On April 16, 2015, an apparent cause evaluation associated with Condition Report 92274, Application of SR 3.0.1, identified the potential that the acceptance criteria in Procedures STS PE-010A, Control Room A/C System Flow Rate Verification A Train, and STS PE-010B, Control Room A/C System Flow Rate Verification B Train, may not have been met when the acceptance criteria was revised on January 3, 2013. The acceptance criteria was revised from greater than 18,360 cubic feet per minute (CFM)and less than 22,440 CFM to a new value of greater than 21,012 CFM, which incorporated instrument uncertainty based on vendor information. The licensee determined that the prior performances of STS PE-010A and STS PE-010B did not meet the new acceptance criteria. Additionally, Procedure STS PE-010B was not performed successfully until July 18, 2013, and Procedure STS PE-010A was not performed successfully until August 13, 2013.

The licensee determined that the apparent cause of this event was information in operability evaluation OE-GK-017 that addressed a separate issue on the same equipment, and enabled control room operators and engineering personnel to rationalize the assumption that the change to the acceptance criteria was bounded and did not impact the ability to meet surveillance requirement SR 3.7.11.1.

The licensees immediate corrective actions included performing corrective maintenance on both control room air conditioning system (CRACS) trains to increase the airflow to meet the procedure acceptance criteria, and subsequent performances of Procedures STS PE-010A and STS PE-010B were successful. An adjustable sheave was installed in the B CRACS train in July 2013 and in the A CRACS train in March 2015.

Furthermore, procedure AP 15C-004, Preparation, Review and Approval of Procedures, Instructions and Forms, is being revised to require operations surveillance coordinator review of technical specification surveillance requirement procedures that result in a change in acceptance criteria.

The licensee event report is closed.

b. Findings

Failure to Adequately Establish Control Room Air Conditioning System Testing Flow Rate Acceptance Criteria

Introduction.

The inspectors identified a Green non-cited violation (NCV) of Technical Specification Limiting Condition for Operation (LCO) 3.7.11 and 3.0.3 for the licensees failure to place the unit in mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, and mode 5 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> with two trains (SGK04A and SGK04B) of the CRACS inoperable.

Specifically, the licensee failed to adequately establish CRACS testing flow rate acceptance criteria, which resulted in train A of the safety-related CRACS being inoperable from October 11, 2005, to August 13, 2013; and train B being inoperable from October 3, 2002, to July 18, 2013.

Description.

Technical Specification LCO 3.7.11, Control Room Air Conditioning System (CRACS), states, Two CRACS trains shall be operable, in modes 1, 2, 3, 4, 5, and 6, and during movement of irradiated fuel assemblies. Technical Specification 3.7.11, Condition B, requires the reactor to be in mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> if one train of the CRACS has been inoperable for 30 days. Condition E, requires immediate entry into Technical Specification 3.0.3, if two CRACS trains are inoperable in modes 1, 2, 3, or 4.

Technical Specification 3.0.3, requires, in part, that when an LCO is not met and the associated actions are not met, the unit shall be placed in a mode or other specified condition in which the LCO is not applicable. Action shall be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit, as applicable, in mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, and mode 5 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />.

On December 18, 1999, Wolf Creek Nuclear Operating Corporation implemented license amendment number 123 that converted the Technical Specifications to the improved Technical Specifications. The amendment included new specification 3.7.11, Control Room Air Conditioning System (CRACS), and the new surveillance requirement SR 3.7.11.1. SR 3.7.11.1 verifies that the heat removal capabilities of CRACS units SGK04A and SGK04B are adequate to remove the heat load assumed in the control room during design basis accidents. This surveillance requirement consists of verifying the heat removal capability of the condenser heat exchanger, ensuring the proper operation of major components in the refrigeration cycle, verification of unit air flow capacity, and water flow measurement. Station Procedures STS PE-010A, Control Room A/C System Flow Rate Verification A Train, and STS PE-010B, Control Room A/C System Flow Rate Verification B Train, were initially issued on December 18, 1999.

For verification of unit air flow capacity, acceptance criteria of greater than 20,400 CFM were specified.

On March 11, 2002, the acceptance criteria associated with unit air flow capacity were inappropriately revised to greater than 18,360 CFM and less than 22,440 CFM based on information in ASME/ANSI N510-1980, Testing of Nuclear Air-Cleaning Systems. NRC finding 05000482/2012004-03, Safety-Related Fan Flow Rate Acceptance Criteria Reduced Below Design Basis Limit, which was documented in Inspection Report 05000482/2012004 (ADAMS Accession #: ML12314A296), discusses how ASME/ANSI N510-1980 was incorrectly applied to the testing of the Class IE electrical equipment air-conditioning system.

The acceptance criteria of Procedures STS PE-010A and STS PE-010B remained the same until January 3, 2013, when the acceptance criteria were revised to greater than 21,012 CFM to correct the previously inadequate acceptance criteria of greater than 18,360 CFM and less than 22,440 CFM. Subsequently, on November 6, 2013, Calculation GK-M-001, Cooling and Heating Load Calculation for Control Room

[Heating Ventilation and Air Conditioning] System Capabilities During Normal Plant Operation and Accident Conditions - (SGK04A/B), Revision 3, was issued and revised the minimum required accident air flow to 20,480 CFM. Accounting for 3 percent instrument uncertainty in accordance with vendor documentation, the minimum required accident air flow during testing would have been 21,094 CFM following the November 6, 2013, calculation revision. On April 14, 2015, Calculation WCN-15-CA-CBV-001, Impact of ESW Pipe Chase on Control Building [Heating, Ventilation, and Air Conditioning], Revision 2, was completed and required the design flow be revised to greater than 20,520 CFM. The testing acceptance criteria of STS PE-010A and STS PE-010B were revised to account for 3 percent instrument uncertainty and to add margin, and were revised to 21,250 CFM (without the additional margin, the minimum required accident air flow plus 3 percent for instrument uncertainty is 21,136 CFM).

21,250 CFM is the current STS PE-010A and STS PE-010B unit air flow acceptance criteria for the SGK04A and SGK04B units.

On April 16, 2015, a Wolf Creek apparent cause evaluation associated with Condition Report 92274, Application of SR 3.0.1, identified the potential that the acceptance criteria in Procedures STS PE-010A and STS PE-010B may not have been met when the acceptance criteria were revised on January 3, 2013. The acceptance criteria had been revised from greater than 18,360 CFM and less than 22,440 CFM to a new value of greater than 21,012 CFM. Licensee Event Report 2015-002-01 was submitted to the NRC on August 26, 2015, and stated, From January 3, 2013, through August 13, 2013, the Conditions and Required Actions of LCO 3.7.11, LCO 3.0.3 and LCO 3.0.4 were not met.

Based on questions by the inspectors the licensee initiated Condition Report 105208 to document that from December 18, 1999, until January 3, 2013, instrument uncertainty was not included in the acceptance criteria of STS PE-010A and STS PE-010B. The inspectors noted that LER 2015-002-01 documented that instrument uncertainty was not included in the acceptance criteria of STS PE-010A and STS PE-010B from March 11, 2002, until January 3, 2013. However, the licensees cause evaluation and Licensee Event Report failed to identify that instrument uncertainty had never been included in the STS PE-010A and STS PE-010B acceptance criteria from December 18, 1999, until March 11, 2002.

Also as a result of questions by the inspectors Condition Report 105208 documented that there was no formal process for procedure writers to consider measurement uncertainty when changing acceptance criteria and that a check for measurement uncertainty in the procedure change process was needed. The inspectors concluded that the licensees cause evaluation and LER failed to identify this concern, which appeared to be the original cause of the licensees failure to establish adequate acceptance criteria and failure to recognize the inoperability of trains A and B of the CRACS.

Based on previous performances of STS PE-010A and STS PE-010B and considering the design basis required flow with instrument uncertainty included, SGK04A was inoperable from October 11, 2005, to August 13, 2013; and SGK04B was inoperable from October 3, 2002, to July 18, 2013. Thus, in accordance with Technical Specification 3.7.11, the station should have entered mode 3 on November 3, 2002, with the SGK04B unit inoperable for greater than 30 days. The station did not meet Technical Specification 3.7.11 until August 13, 2013. The SGK04A and SGK04B units were simultaneously inoperable from October 11, 2005, through July 18, 2013. Although the SGK04A and SGK04B units were simultaneously inoperable for an extended period of time, the inspectors noted that the SGK04 units functioned and provided control room cooling throughout the inoperability period, the inspectors noted that licensee air flow calculations contained additional margin, and the inspectors noted that measured air flow rate testing results were never less than required design basis flow rates by more than 1.8 percent, which is less than the 3 percent instrument uncertainty.

The licensees immediate corrective actions included corrective maintenance on the CRACS trains to increase the airflow to meet acceptance criteria limits, Procedures STS PE-010A and STS PE-010B were performed successfully on March 6, 2015, and January 13, 2015, for A and B trains, respectively. Condition Report 105208 was initiated by the licensee for evaluation of any necessary process changes and extent of condition. Furthermore, procedure AP 15C-004, Preparation, Review and Approval of Procedures, Instructions and Forms, is being revised to require operations surveillance coordinator review of technical specification surveillance procedures that result in a change in acceptance criteria.

Analysis.

The inspectors determined that Wolf Creeks failure to establish adequate CRACS testing flow rate acceptance criteria was a performance deficiency that impacted the stations ability to adequately implement Technical Specification surveillance requirement SR 3.7.11, Control Room Air Conditioning System (CRACS). This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the station operated in a condition prohibited by Technical Specifications with train A of the safety-related CRACS inoperable from October 11, 2005, to August 13, 2013, and train B inoperable from October 3, 2002, to July 18, 2013.

In accordance with Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Exhibit 2 of Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and April 29, 2015, respectively, the performance deficiency affects a mitigating SSC. The inspectors determined this finding was not a deficiency affecting the design or qualification of a mitigating SSC that maintained its operability or functionality, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of function of at least a single train for greater than its Technical Specification allowed outage time, and the finding did not represent an actual loss of function of one or more non-Technical Specification trains of equipment designated as high safety-significant. Therefore, the inspectors determined the finding was of very low safety significance (Green).

The inspectors determined that in accordance with Inspection Manual Chapter 0310, Aspects Within The Cross-Cutting Areas, issued December 4, 2014, the finding has a cross-cutting aspect in the area of human performance, change management, because leaders did not use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority. Specifically, there is not currently a formal process for procedure writers to consider measurement uncertainty when establishing and changing testing acceptance criteria, which resulted in extended inoperability of both the SGK04A and SGK04B units following significant changes to Technical Specifications that included adding surveillance requirements for the SGK04A and SGK04B units in 1999. This issue is indicative of current performance because the same issue would be expected to occur today. Condition Report 105208, which was written in response to the inspectors questions, documents that a check for measurement uncertainty in the procedure change process is needed [H.3].

Enforcement.

Technical Specification 3.7.11, Condition B, requires the reactor to be in mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> if one train of the CRACS has been inoperable for 30 days while in mode 1, 2, 3, or 4. Contrary to the above, from November 3, 2002, until August 13, 2013, the reactor was not in mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> with one train of the CRACS inoperable for 30 days while in mode 1, 2, 3, or 4. Specifically, the B train of the CRACS was inoperable for 30 days while in mode 1, 2, 3, and 4. The licensee entered this condition into its corrective action program as Condition Report 95378. The licensees immediate corrective actions included corrective maintenance on the CRACS to increase the airflow to meet acceptance criteria limits. Surveillance Procedures STS PE-010A and STS PE-010B were performed successfully on March 6, 2015, and January 13, 2015, for A and B trains, respectively. Condition Report 105208 was initiated by the licensee for any necessary process changes and extent of condition actions. Furthermore, procedure AP 15C-004, Preparation, Review and Approval of Procedures, Instructions and Forms, is being revised to require Operations Surveillance Coordinator review of Technical Specification surveillance procedures that result in a change in acceptance criteria. Because this violation was of very low safety significance and this issue was entered into the licensees corrective action program, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy.

(NCV 05000482/2016002-01, Failure to Adequately Establish Control Room Air Conditioning System Testing Flow Rate Acceptance Criteria)

.4 (Closed) LER 05000482/2015-004-00: Inadequate Procedure Results in Two

Containment Isolation Valves being in a Condition Prohibited by Technical Specifications, and LER 05000482/2015-004-01: Incorrect Decision Results in Two Containment Isolation Valves being in a Condition Prohibited by Technical Specifications On May 5, 2015, it was discovered that the motive force (air supply) was not removed for two containment shutdown purge valves as required by Technical Specification 3.6.3, Containment Isolation Valves. The motive force was restored to allow the performance of Procedure STS KJ-001A, Integrated Diesel Generator and Safeguards Actuation Test - Train A, on April 26, 2015. After performance of Procedure STS KJ-001A, the motive force was not removed for the two containment shutdown purge valves. The plant entered Mode 4 on April 28, 2015.

Upon discovery, the air supply valves for the two containment shutdown purge valves were locked closed, removing the motive force. The cause of the event was determined to be the decision to only track components listed on a locked component log using Form APF 21G-001-01, Log of Locked Component Manipulations, Revision 1, during plant start up, which allowed a mode change with components out of position. Each impacted penetration flow path had a redundant valve that was closed with the motive force removed.

The licensee implemented the following corrective actions:

(1) On May 5, 2015, the air supply valves for GTHZ0007 and GTHZ0009 were locked closed and verified, which removed the motive force; and

(2) Procedure AP 21G-001, Control of Locked Component Status, was revised to ensure an Equipment Out of Service Log entry was made for components required to be locked by technical specifications. The inspectors determined that this constituted a licensee-identified violation, and the enforcement aspects of this violation are discussed in Section 4OA7 of this inspection report.

The licensee event reports are closed.

These activities constituted completion of four event follow-up samples, as defined in Inspection Procedure 71153.

4OA5 Other Activities

(Closed) Unresolved Item (URI)05000482/2015001-01, Questions Related to Ultrasonic Examination of Reactor Vessel Flange Stud Hole Threads On May 7, 2015, the NRC issued Wolf Creek Nuclear Operating Corporation a URI related to the examination technique utilized by the licensee to perform reactor vessel flange ligament inspections for ASME Code compliance. The concern was that the technique being utilized by the licensee might not provide adequate coverage of the required examination area and may not be capable of detecting indications orientated on a plane normal to the axis of the stud that were equal to or exceeded 0.2 inch, as measured radially from the root of the thread, as required by the licensee's procedure and Section XI of the ASME Code. Demonstrations of the technique were completed by the licensee and verified that the technique could detect flaws in the required examination area. The results of these demonstrations were reviewed by the NRC staff and considered acceptable. Based on these facts, the NRC considers this item to be closed and no follow-up inspection activity for this item is planned.

No findings were identified. The unresolved item is closed.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On May 26, 2016, regional inspectors presented the final heat sink performance inspection results to Mr. J. McCoy, Vice President, Engineering, and other members of the licensee staff.

The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. Proprietary information was returned or destroyed.

On June 10, 2016, regional inspectors presented the inservice inspection activity inspection results via telephonic exit to Mr. W. Muilenburg, Supervisor, Licensing. The licensee acknowledged the issue presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On June 23, 2016, regional inspectors presented the radiation safety inspection results to Mr. M. Skiles, and other members of the licensee staff via teleconference. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On July 27, 2016, the resident inspectors presented the inspection results to Cleveland Reasoner, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

4OA7 Licensee-Identified Violations

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

• Technical Specification 5.7.2 states, in part, that high radiation areas with dose rates greater than 1.0 rem per hour at 30 centimeters shall be conspicuously posted as a high radiation area and shall be provided with a locked or continuously guarded door or gate to prevent unauthorized entry. Contrary to the above, on January 27, 2016, room 7406 on the 2013 foot elevation of the radwaste building areas had dose rates greater than 1.0 rem per hour and was not conspicuously posted as a high radiation area nor provided with a locked or continuously guarded door or gate to prevent unauthorized entry. This issue was identified by radiation protection technicians performing radiological surveys in the area. The licensee documented this issue in the corrective action program as Condition Report 102344. The finding was determined to be of very low safety significance (Green) because it was not an as-low-as-reasonably-achievable planning issue, there was no overexposure or potential for overexposure, and the licensees ability to assess dose was not compromised.

• Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be accomplished in accordance with documented instructions, procedures, or drawings of a type appropriate to the circumstances. Licensee Procedure AP 26C-004, Operability Determination and Functionality Assessment, Revision 32, an Appendix B quality related procedure, provides instructions for determining whether equipment is operable when oil leakage is identified. Procedure AP 26C-004, Step 6.2.1.1, states in part, that if operability of a system/component is being questioned due to system leakage that the leak rate has been quantified and total identified leakage for the affected system has been determined and compared to the limits of Attachment F, Allowable Oil Leakage for Successful Mission. Contrary to the above, from May 28, 2016, until May 31, 2016, operability of a system/component was being questioned due to system leakage and the leak rate had not been quantified and the total identified leakage for the affected system was not determined and compared to the limits of Attachment F, Allowable Oil Leakage for Successful Mission. Specifically, operability of the B component cooling water pump was questioned due to system leakage as documented in Condition Report 104910, and the leak rate had not been quantified and the total identified leakage for the affected system was not determined, which resulted in the immediate operability determination being incorrect and the immediate operability determination requiring revision.

Immediate corrective actions included revising the immediate operability determination for the B component cooling water pump from operable to inoperable, generating a required reading for senior reactor operators, and documenting Condition Report 104959. Using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Finding At-Power, dated June 19, 2012, the inspectors determined this finding was not a deficiency affecting the design or qualification of a mitigating SSC that maintained its operability or functionality, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of function of at least a single train for greater than it Technical Specification allowed outage time, and the finding did not represent an actual loss of function of one or more non-Technical Specification trains of equipment designated as high safety-significant. Therefore, the inspectors determined the finding was of very low safety significance (Green).

• Technical Specification 3.4.3, [Reactor Coolant System] Pressure and Temperature Limits, states, in part, that reactor coolant system pressure, reactor coolant system temperature, and reactor coolant system heatup and cooldown rates shall be maintained within the limits specified in the Pressure and Temperature Limits Report (PTLR).

Section 2.1.2 of the PTLR specifies that the reactor coolant system shall be maintained within the parameters of Figure 2.1-1 of the PTLR, which specifies a minimum pressure of 0 psig. Required Action C.1 of Technical Specification 3.4.3 specifies that with the reactor coolant system parameters outside the limits of the PTLR, restore the parameters to within the limits immediately. Contrary to the above, on May 8, 2011, and March 30, 2013, with the reactor coolant system parameters outside the limits of the PTLR, parameters were not restored to within the limits immediately. Specifically, the licensee drew a vacuum on the reactor coolant system to less than 0 psig to support filling operations but did not take action to immediately restore the reactor coolant system pressure to greater than or equal to 0 psig, as specified in the PTLR. The licensee placed this issue in the corrective action program as Condition Report 78920.

The licensee performed Engineering Evaluation EER 92-BB-02 and determined that drawing a vacuum on the reactor coolant system would not result in excessive stresses for reactor coolant system structures, systems and components. Using Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, dated May 9, 2014, this issue screened to Green because it did not result in a loss of reactor coolant system barrier integrity.

• Technical Specification 3.4.15, [Reactor Coolant System] Leakage Detection Instrumentation, states, in part, that reactor coolant system leakage detection instrumentation shall be operable, including the containment sump level and flow monitoring system. Required Action A of Technical Specification 3.4.15, states, in part, that with the required containment sump level and flow monitoring system inoperable, restore the required containment sump level and flow monitoring system to operable status within 30 daysif the required action and associated completion time are not met, Condition E requires the reactor to be in mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Contrary to the above, from the period of July 13, 2013, to November 20, 2013, with the containment sump level and flow monitoring system inoperable for greater than 30 days, the reactor was not placed in mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

Specifically, the instrument tunnel sump level indication was inoperable because of erratic indication, but the licensee did not take the required action of Technical Specification 3.4.15. The licensee placed this issue in the corrective action program as Condition Report 84690. Using Manual Chapter 0609, Appendix A, Significance Determination Process, for Findings at Power, dated June 19, 2012, this issue screened to Green because it did not result in reactor coolant system leakage or degrade the licensees ability to detect and mitigate a small break loss of coolant accident.

• Technical Specification 3.6.3, Containment Isolation Valves, requires each containment isolation valve to be operable in modes 1, 2, 3, and 4. To be operable, containment isolation valves GTHZ0007 and GTHZ0009, which are Category 3 valves, must be closed with the motive force removed. Technical Specification 3.6.3, Condition A, Required Action A.1, requires, in part, that the affected penetration flow path for any inoperable Category 3 containment isolation valve be isolated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Additionally, Required Action A.2, requires, in part, that the licensee verify the affected penetration flow path is isolated prior to entering mode 4 from mode 5. Contrary to the above, from April 28, 2015, through May 5, 2015, the licensee failed to verify the affected penetration flow path was isolated prior to entering mode 4 from mode 5 on April 28, 2015. As a result, Technical specification 3.6.3, Condition A, was not met On May 5, 2015, the licensee discovered that the motive force for valves GTHZ0007 and GTHZ0009 was not removed and the air supply valves had not been locked closed, and the affected penetration flow paths were not isolated prior to entering mode 4 from mode 5 on April 28, 2015. The inspectors noted that although the motive force was not removed for valves GTHZ0007 and GTHZ0009, the valves were in their closed safeguards positions and redundant valves in series were closed with the motive force removed, which ensured each penetration flow path had one operable valve closed with its motive force removed. Using Exhibit 3, Barrier Integrity Screening Questions, of Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Finding At-Power, dated June 19, 2012, the inspectors determined the finding did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), or heat removal components, and the finding did not involve an actual reduction in function of hydrogen igniters in the reactor containment. Therefore, the inspectors determined that this finding is of very low safety significance (Green).

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Adkinson, Environmental Biologist IV

T. Baban, Manager, System Engineering

W. Brown, Superintendent, Security Operations

T. Broyles, Manager, Information Services

D. Campbell, Superintendent, Maintenance

C. Carman, Supervisor, Chemistry

J. Dorsey, Technician I, Chemistry

T. East, Superintendent, Emergency Planning

J. Edwards, Manager, Operations

D. Erbe, Manager, Security

R. Flannigan, Manager, Nuclear Engineering

K. Fredrickson, Engineer, Licensing

J. Freeman, Supervisor of Treatment Systems, Operations

J. Fritton, Oversight

C. Garcia, Supervisor Engineer

D. Gibson, Master HP Technician

C. Gross, Manager, Chemistry

D. Grove, Superintendent, Maintenance Support

C. Hafenstine, Manager, Regulatory Affairs

A. Heflin, President and Chief Executive Officer

S. Henry, Manager, Integrated Plant Scheduling

P. Herrman, Manager, Engineering Programs

R. Hobby, Licensing Engineer

J. Isch, Superintendent, Operations Work Controls

J. Jenek, Quality Specialist iii

B. Ketchum, Supervisor Engineer

B. Lee, Licensed Supervising Instructor

M. Legresley, Engineer

K. Lemaster, Master Technician, Chemistry

D. Mand, Manager, Design Engineering

N. Mayhew, Engineer III

J. McCoy, Vice President, Engineering

M. McMullen, Design Engineer

C. Medenciy, Radioactive Materials Shipper

C. Menke, Supervisor Maintenance

K. Miller, Master Instruments and Controls Technician

N. Mingle, Engineer

K. Mitchell, Master Chemistry Technician

W. Muilenburg, Supervisor, Licensing

L. Ratzlaff, Manager, Maintenance

R. Raymer, Engineering Technologist V

C. Reasoner, Site Vice President

T. Rice, Technician III, Safety

J. Rudeen, Supervisor, Regulatory Support

K. Sheridan, Engineer III

Attachment 1

M. Skiles, Manager, Radiation Protection

T. Slenker, Supervisor, Operations Support

S. Smith, Plant Manager

M. Staiger, Engineer II

L. Stevens, Licensing Engineer V

L. Stone, Licensing Engineer V

A. Stull, Vice President and Chief Administrative Officer

J. Suter, Supervisor Engineer

M. Tate, Superintendent, Security Operations

J. Truelove, Supervisor, Chemistry

J. Vopat, Technician II, Chemistry

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened/Closed

05000482/2016002-01 NCV Failure to Adequately Establish Control Room Air Conditioning System Testing Flow Rate Acceptance Criteria (4OA3)

Closed

05000482/2014-001-00 LER Failure to Comply with Required Action of Technical Specification 3.4.3 while Performing a Vacuum Fill of the Reactor Coolant System (4OA3)

05000482/2014-004-00 LER Condition Prohibited by Technical Specifications due to an Instrument Tunnel Sump Level Indication Transmitter Incompatible with the Containment Environment (4OA3)

05000482/2015-001-01 URI Questions Related to Ultrasonic Examination of Reactor Vessel Flange Stud Hole Threads (4OA5)

05000482/2015-002-00 LER Two Control Room Air Conditioning Trains Inoperable Due to Failure to Meet Surveillance Requirement (4OA3)

05000482/2015-002-01 LER Two Control Room Air Conditioning Trains Inoperable Due to Failure to Meet Surveillance Requirement (4OA3)

05000482/2015-004-00 LER Inadequate Procedure Results in Two Containment Isolation Valves being in a Condition Prohibited by Technical Specifications (4OA3)

05000482/2015-004-01 LER Incorrect Decision Results in Two Containment Isolation Valves being in a Condition Prohibited by Technical Specifications (4OA3)