IR 05000482/2017003

NRC Integrated Inspection Report 05000482/2017003 and Exercise of Enforcement Discretion

ML17311B223
Person / Time
Site:	Wolf Creek
Issue date:	11/07/2017
From:	Nick Taylor NRC/RGN-IV/DRP/RPB-B
To:	Heflin A Wolf Creek
nick taylor
References
EA-17-170 IR 2017003
Download: ML17311B223 (51)

Text

ember 7, 2017

SUBJECT:

WOLF CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000482/2017003 AND EXERCISE OF ENFORCEMENT DISCRETION

Dear Mr. Heflin:

On September 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Wolf Creek Generating Station. On October 23 and November 7, 2017, the NRC inspectors discussed the results of this inspection with Mr. J. McCoy, Vice President, Engineering, and other members of your staff. The results of this inspection are documented in the enclosed report.

NRC inspectors documented three findings of very low safety significance (Green) in this report.

Three of these findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violations or significance of these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement; 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; and the NRC resident inspector at the Wolf Creek Generating Station.

Tornado-generated missile protection violations were identified for the following technical specifications: 3.7.1 Main Steam Safety Valves and 3.7.4 Atmospheric Relief Valves. Because the violations were identified during the discretion period covered by Enforcement Guidance Memorandum 15-002, Revision 1, Enforcement Discretion for Tornado Missile Protection Non-compliance, and because the licensee was implementing compensatory measures, the NRC is exercising enforcement discretion by not issuing an enforcement action and is allowing continued reactor operation.

This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.

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 05000482/2017003 w/ Attachments:

1. Supplemental Information 2. Request for Information

SUNSI Review: NHT ADAMS: Non-Publicly Available Non-Sensitive Keyword:

By: NHT/dll Yes No Publicly Available Sensitive NRC-002 OFFICE SRI:DRP/B RI:DRP/B C:DRS/OB C:DRS/PSB2 C:DRS/EB1 C:DRS/EB2 NAME DDodson FThomas VGaddy HGepford TFarnholtz GWerner SIGNATURE /RA/ /RA/ /RA/ /RA/ /RA/ /RA/

DATE 11/02/17 11/02/17 10/25/17 10/25/2017 10/25/2017 10/25/2017 OFFICE TL:DRS/IPAT ORA/ACES BC:DRP/B NAME THipschman MHay NTaylor SIGNATURE /RA/ /RA/JKramer /RA/

for DATE 10/25/17 10/26/17 11/7/17

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000482 License: NPF-42 Report: 05000482/2017003 Licensee: Wolf Creek Nuclear Operating Corporation Facility: Wolf Creek Generating Station Location: 1550 Oxen Lane NE Burlington, KS 66839 Dates: July 1 through September 30, 2017 Inspectors: D. Dodson, Senior Resident Inspector F. Thomas, Resident Inspector T. Farina, Senior Operations Engineer P. Jayroe, Reactor Engineer E. Ruesch, J.D., Senior Reactor Inspector Approved Nicholas H. Taylor By: Chief, Project Branch B Division of Reactor Projects Enclosure

SUMMARY

IR 05000482/2017003; 07/01/2017 - 09/30/2017; Wolf Creek Generating Station; Maintenance

Effectiveness, Operability Determinations and Functionality Assessments, and Follow-up of Events and Notices of Enforcement Discretion The inspection activities described in this report were performed between July 1 and September 30, 2017, by the resident inspectors at Wolf Creek Generating Station and inspectors from the NRCs Region IV office. Three findings of very low safety significance (Green) are documented in this report. Three of these findings involved violations of NRC requirements. The significance of inspection findings is indicated by their color (i.e., Green, greater than Green, White, Yellow, or Red), determined using Inspection Manual Chapter 0609,

Significance Determination Process, dated April 29, 2015. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects within the Cross-Cutting Areas, dated December 4, 2014. 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, dated July 2016.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green non-cited violation of 10 CFR 50.65(b)(2)(ii),

because the licensee did not adequately include nonsafety-related SSC functions within the scope of the maintenance rule monitoring program. Specifically, the licensee failed to adequately include within the scope of the maintenance rule monitoring program the function of draining. This scoping issue has resulted in a failure to monitor floor drain degradation and to provide reasonable assurance that safety-related SSCs in an estimated 76 rooms are capable of fulfilling their intended functions. Immediate corrective actions included entering the condition into the corrective action program as Condition Report 116319 and later as Condition Report 116851.

The inspectors determined that the licensees failure to meet the requirements of 10 CFR 50.65(b)(2)(ii) and appropriately place the function of draining, for nonsafety-related floor drains in up to 76 rooms containing safety-related SSCs, within the scope of the maintenance rule monitoring program was a performance deficiency. The performance deficiency was more than minor, because it is associated with the Protection Against External Factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, Significance Determination Process (SDP)for Findings At-Power, and determined the finding was of very low safety significance (Green). The inspectors determined that the finding did not have a cross-cutting aspect because the issue was not indicative of current performance. (Section 1R12)

Green.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to establish adequate measures to ensure that the design bases are correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee did not ensure the auxiliary feedwater system design basis was adequately represented in the Technical Specification Bases; as a result, the Technical Specification Bases and other station procedures allowed for one train of essential service water supply to the turbine-driven auxiliary feedwater pump to be removed from service without recognition that auxiliary feedwater operability was impacted. Immediate corrective actions included entering Condition Reports 113304 and 116852 into the corrective action program and incorporating a note on operations turnover documents to temporarily postpone applicable portions of the operations quarterly tasks.

The licensee also completed a past operability review, and created actions to develop a license amendment request to add a specific Technical Specification condition and submit for NRC approval.

The failure to ensure the auxiliary feedwater system design basis was adequately represented in the Technical Specification Bases was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is associated with the design control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings At-Power, and determined this finding was of very low safety significance (Green). The inspectors determined that the finding has a problem identification and resolution cross-cutting aspect in the area of evaluation because the organization did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. This issue is indicative of current performance because the evaluation of Condition Report 111808 in May 2017 was a reasonable opportunity for the licensee to identify that the Technical Specification Bases was inadequate [P.2]. (Section 1R15)

Green.

The inspectors reviewed a Green, self-revealed non-cited violation of Technical Specification 5.4.1.a for the licensees failure to ensure that maintenance that can affect the performance of safety-related equipment was properly pre-planned and performed in accordance with written procedures, documented, instructions, or drawings appropriate to the circumstances. Specifically, the licensee failed to verify that the wiring in the transformer primary differential protective relay was landed on the correct termination point, and as a result, the station experienced an unplanned loss of normal offsite power to bus NB01, the train A Class 1E electrical bus. The licensee took the immediate corrective actions of working with Westar to ensure the protective relay wiring termination issue for transformer 7 was identified and corrected, and that transformer 7 was returned to service. The licensee also updated procedure AP 21C-001 to include additional detail and steps that require work instructions for post maintenance testing of current transformer wiring to ensure independent verification of wiring terminations. The licensee entered the issue into the corrective action program as Condition Reports 109467 and 116849.

The licensees failure to verify that the primary and secondary differential relay circuitry is capable of performing its intended design function following maintenance was a performance deficiency. The performance deficiency was more than minor because it affected the design control attribute of the Mitigating Systems 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 evaluated the finding using Exhibit 3, "Mitigating Systems Screening Questions," of Inspection Manual Chapter 0609, Appendix G, Attachment 1, "Shutdown Operations Significance Determination Process Phase I Initial Screening and Characterization of Finding," and Appendix G, "Shutdown Operations Significance Determination Process." The inspectors determined the finding was of very low safety significance (Green). The inspectors determined that the finding has a human performance cross-cutting aspect in the area of resources because leaders did not ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. This issue is indicative of current performance because the issue occurred in the last three years [H.1].

(Section 4OA3)

PLANT STATUS

Wolf Creek Generating Station began the inspection period operating at full power. On July 26, 2017, operators reduced power to approximately 66 percent following the loss of the Wolf Creek-Benton offsite 345 kV line as a result of heavy offsite storms. The plant was restored to approximately full power on July 28, 2017, and the plant operated at or near full power for the rest of the 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 September 28, 2017, 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 an excessive heat warning on July 21, 2017, and the licensees planned implementation of these procedures. The inspectors evaluated 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:

• July 18, 2017, safety injection train B

• August 8, 2017, accumulator compressed air system

• August 22 and 24, 2017, temporary diesel fire pump

• August 29, 2017, auxiliary feedwater pump A

• September 6, 2017, component cooling water train A

• September 13, 2017, emergency diesel generator train A 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 and trains were correctly aligned for the existing plant configuration.

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

b. Findings

No findings were identified.

1R05 Fire Protection

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:

• July 20, 2017, fire area A-24, pipe penetration room A, elevation 2,000 feet

• July 20, 2017, fire area A-25, pipe penetration room B, elevation 2,000 feet

• August 16, 2017, fire area A-1, general area (area 5), elevation 1,974 feet

• September 13, 2017, fire area C-9, engineered safety feature switchgear room (no. 1), elevation 2,000 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.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On September 21, 2017, the inspectors observed a portion of 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 August 17, 2017, 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 control rod parking activities.

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.

.3 Annual Review of Requalification Examination Results

a. Inspection Scope

The inspector conducted an in-office review of the annual requalification training program to determine the results of this program.

On July 6, 2017, the licensee informed the inspector of the following Wolf Creek Nuclear Operating Corporation operating test results:

• 8 of 8 crews passed the simulator portion of the operating test

• 48 of 48 licensed operators passed the simulator portion of the operating test

• 48 of 48 licensed operators passed the job performance measure portion of the operating test There were no remediations performed for the operating tests. One licensed reactor operator did not take the annual operating test due to current enrollment in an initial license training class.

The inspector completed one inspection sample of the annual licensed operator requalification program.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Routine Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed two instances of degraded performance or condition of safety-significant structures, systems, and components (SSCs):

• September 25, 2016, safety injection pump A, failed pump performance test during Mode 6

• April 25, 2017, train A pipe penetration room clogged floor drains 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 two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50.65(b)(2)(ii), because the licensee did not adequately include nonsafety-related SSC functions within the scope of the maintenance rule monitoring program. Specifically, the licensee failed to adequately include within the scope of the maintenance rule monitoring program the function of draining. This scoping issue has resulted in a failure to monitor floor drain degradation and to provide reasonable assurance that safety-related SSCs in an estimated 76 rooms are capable of fulfilling their intended functions.

Description.

The inspectors documented NRC-identified non-cited violation 05000482/2017002-01, Failure to Ensure Safety-Related Valves were Adequately Protected from Internal Flooding Hazards, in the 2017002 integrated inspection report (ADAMS Accession Number ML17223A285). This issue focused on the licensees failure to establish adequate measures to ensure that floor drains in safety-related areas remained free of debris and safety-related components remained capable of performing their function. Specifically, on April 25, 2017, two of three floor drains were found clogged in the train A safety-related piping penetration room.

The inspectors noted that five functions were identified in the maintenance rule as associated with the LF or Floor & Equipment Drains System. Specifically, the following five functions were included: LF-01, Provides containment isolation for one system piping penetrating containment barrier (Penetration number P-32); LF-02, Provides indication or alarms of a potential flooding condition in the Containment,

[residual heat removal] Pump Rooms, Control Building, Fuel Building and Auxiliary Building; LF-03, Provides isolation of discharge of [residual heat removal], Aux Building and Control Building sumps on [safety injection] signal to prevent pumping potentially radioactive water to other parts of the plant; LF-04, Provide detection of Spent Fuel Pool Leakage; and LF-05, Provides detection of leakage into refueling pool and four containment cooler standpipes, instrument tunnel, non-radioactive pipe tunnel, hot machine shop, spent fuel pool, solidification area, two radwaste building areas, and auxiliary building sumps. Of these five functions, LF-01, LF-02, and LF-03 were included within scope.

The inspectors questioned the licensee with respect to the scoping of the floor drains and reviewed a licensee position paper that concluded, The floor drain system does not have a Maintenance Rule function of directing water out of safety-related (SR) areas.

This is primarily due to the fact if the floor drains were to fail, as in clog, you have to have another event to introduce water into the area.

In the case of the floor drains and the function of draining, the inspectors noted that the failure of nonsafety-related floor drains at Wolf Creek could prevent a number of safety-related functions from being fulfilled. Specifically, the inspectors noted the issue described in the 2017002 inspection report, as described. The inspectors also noted that flood calculations associated with an estimated 76 safety-related rooms, could be adversely impacted such that unanticipated flood heights in these rooms due to failure of floor drains to function to remove water could impact the safety functions of safety-related SSCs in the impacted rooms. The inspectors also noted language discussed in Section 3.6.1.1.h.2.m of the Updated Safety Analysis Report, which states, in part:

A survey of all potential internal flooding sources was performed for all rooms with safety-related componentsFrom this survey, calculations were performed to determine the worst case flood level in each of these rooms...Assumptions used in arriving at the worst case flooding event are as follows: Rooms drain through the floor drain(s).

Considering the assumptions of the internal flooding analysis, as described in the Updated Safety Analysis Report, the inspectors also reviewed relevant corrective action program documents like Condition Report 2008-005940 and Performance Improvement Request 2001-2783, which reviewed the maintenance rule scoping of drains and their effect on safety related indication. The licensee noted that the LF-02 function focuses on the safety-related level transmitters located in the building sumps and noted that the level transmitters can only provide indication of flooding if water is transferred to the sump. The request goes on to note, Non-safety related floor drains are relied upon to transfer the water to each sump. Failure or plugging of the non-safety related floor drains could cause the safety related function to provide indication of flooding to fail.

Therefore the non-safety related floor drains appear to meet the maintenance rule scoping criteria.

The Performance Improvement Request 2001-2783 evaluation later concluded, in part, that the function of the floor drains are not relied upon for accident or transient mitigation per review of Updated Safety Analysis Sections 3 and 9, and the failure of the floor drains will not prevent a safety-related SSC from fulfilling its safety-related function. The 2001-2783 Performance Improvement Request evaluations conclusions were then incorporated into the maintenance rule scoping basis and were similarly affirmed by the conclusions of Condition Report 2008-005940.

Considering all of the above information the inspectors determined that the draining function of the floor drain system should have been included within the scope of the maintenance rule monitoring program. Immediate corrective actions included entering the condition into the corrective action program as Condition Reports 116319 and 116851.

Analysis.

The inspectors determined that the licensees failure to meet the requirements of 10 CFR 50.65(b)(2)(ii) and appropriately place the function of draining, for nonsafety-related floor drains in up to 76 rooms containing safety-related SSCs, within the scope of the maintenance rule monitoring program was a performance deficiency that was within the licensees ability to foresee and correct and should have been prevented. The inspectors determined that the failure to scope the function of draining in the maintenance rule was more than minor, because it is associated with the Protection Against External Factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the licensee failed to detect floor drain degradation associated with rooms containing safety-related equipment and to provide reasonable assurance that safety-related SSCs in an estimated 76 rooms are capable of fulfilling their intended functions. The inspectors evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined this finding did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors). Therefore, the inspectors determined the finding was of very low safety significance (Green).

The inspectors determined that the finding did not have a cross-cutting aspect because the issue was not indicative of current performance.

Enforcement.

Title 10 CFR 50.65(b)(2)(ii) requires, in part, that the scope of the monitoring program specified in paragraph (a)(1) shall include nonsafety related SSCs whose failure could prevent safety-related SSCs from fulfilling their safety-related function. Contrary to the above, until October 3, 2017, the scope of the monitoring program specified in paragraph (a)(1) did not include nonsafety related SSCs whose failure could prevent safety-related SSCs from fulfilling their safety-related function.

Specifically, the draining function of nonsafety related floor drains was not included within the licensees monitoring program and the failure to drain could have prevented safety-related SSCs in an estimated 76 rooms from fulfilling their safety-related functions. Immediate corrective actions included entering the condition into the corrective action program as Condition Reports 116319 and 116851. This violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000482/2017003-01, Programmatic Failure to Scope Floor Drain Function within the Maintenance Rule Monitoring Program.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed seven 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:

• July 11, 2017, train B centrifugal charging pump planned maintenance

• July 18, 2017, train A safety injection pump and train A containment spray pump planned maintenance

• August 1, 2017, train B essential service water pump planned maintenance

• August 8, 2017, train B motor driven auxiliary feedwater pump planned maintenance

• August 22 and 23, 2017, diesel fire pump planned maintenance

• August 31, 2017, planned lightning mast installation in the switchyard and turbine driven auxiliary feedwater pump planned maintenance

• September 12, 2017, extended train B emergency diesel generator planned maintenance 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 result of the assessments.

Additionally, on July 24, 2017, the inspectors observed emergent work activities to troubleshoot circuit breaker 13-48 annunciator ground fault indications that had the potential to affect the functional capability of mitigating systems.

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 eight 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

Operability Determinations

a. Inspection Scope

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

• June 26, 2017, past operability determination of turbine driven auxiliary feedwater with one train of essential service water supply out of service

• August 23, 2017, functionality assessment of diesel fire pump driveshaft out of tolerance

• August 31 and September 7, 2017, operability determinations of atmospheric relief valve (ARV) and main steam safety valve (MSSV) susceptibility to tornado generated missiles

• September 11, 2017, operability determination of train B emergency diesel generator tornado damper sticking

• September 12, 2017, operability determination of train B emergency diesel generator stator surface anomalies 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 five operability and functionality review samples as defined in Inspection Procedure 71111.15.

.1 Failure to Ensure the Design Basis was Adequately Represented in the Technical

Specification Bases

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to establish adequate measures to ensure that the design bases are correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee did not ensure the auxiliary feedwater system design basis was adequately represented in the Technical Specification Bases; as a result, the Technical Specification Bases and other station procedures allowed for one train of essential service water supply to the turbine-driven auxiliary feedwater pump to be removed from service without entry into applicable Technical Specification action statements.

Description.

The inspectors documented NRC-identified non-cited violation 05000482/2017002-02, Failure to Declare Train A Component Cooling Water Inoperable, in the 2017002 integrated inspection report (ADAMS Accession Number ML17223A285), for the licensees failure to declare the emergency make-up to train A component cooling water valve inoperable when it was out of service, which resulted in train A component cooling water out of service for longer than its Technical Specification allowed outage time. The licensee entered the issue into the corrective action program as Condition Report 111808 and completed a basic cause evaluation.

The inspectors reviewed the basic cause evaluationcompleted on May 23, 2017for Condition Report 111808 and noted that the extent of condition considered the auxiliary feedwater system as one of two systems with makeup capability from essential service water. The evaluation concluded that the extent of condition was bound to the seven events where Technical Specification 3.7.7 was not entered associated with component cooling water operability as previously described. The inspectors also noted that the cause evaluation described the Technical Specification 3.7.5 Bases, which states:

The inoperability of a single supply line or a single suction isolation valve from an [essential service water] train to the turbine driven [auxiliary feedwater] train pump causes a loss of redundancy in [essential service water] supply to the pump but does not render the turbine driven [auxiliary feedwater] train inoperablethe turbine driven [auxiliary feedwater] train is OPERABLE based on the remaining OPERABLE [essential service water] supply line.

The inspectors noted that although the cause evaluation discussed the Technical Specification 3.7.5 Bases, the evaluation did not evaluate the adequacy of the bases or evaluate design basis information such as the Updated Safety Analysis Report.

The inspectors reviewed applicable sections of the Updated Safety Analysis Report and noted Table 15.0-7, Single Failures Assumed in Accident Analyses, which notes that the worst failure assumed for a feedwater system pipe break is one protection train.

Section 15.2.8.2, Analysis of Effects and Consequences, of the accident analyses within Section 15.2.8, Feedwater System Pipe Break, states that the total auxiliary feedwater flow delivered to the three intact steam generators is assumed to be 563 gallons per minute, which bounds either a single failure of the turbine-driven auxiliary feedwater pump or one motor-driven auxiliary feedwater pump. Credit is also taken for the discharge flow control device installed on the auxiliary feedwater header common to both the motor driven and turbine driven auxiliary feedwater pumps. Due to this discharge flow control device, the intact steam generator receiving auxiliary feedwater from both the motor driven and turbine driven auxiliary feedwater pumps is assumed to receive no more than 250 gallons per minute. The remaining two intact steam generators, which receive auxiliary feedwater from only the turbine driven auxiliary feedwater pump, are assumed to receive approximately 157 gallons per minute each.

The inspectors noted that when an essential service water supply valve to the turbine-driven auxiliary feedwater pump is removed from service for planned maintenance, the assumptions of the accident analyses would not be met. Specifically, when the train A essential service water supply to the turbine-driven auxiliary feedwater pump is out of service for planned maintenance, a single failure of a protection train (like the train B essential service water pump, emergency diesel, or bus) could make the turbine driven auxiliary feedwater and the train B motor-driven auxiliary feedwater pumps inoperable simultaneously. Hence, only the train A motor-driven auxiliary feedwater pump would be providing flow and would not be capable of delivering the assumed 563 gallons per minute to the three intact steam generators as assumed.

The inspectors considered Procedures SYS OQT-001A, Operations A Train Quarterly Tasks, and SYS OQT-001B, Operations B Train Quarterly Tasks, which are performed quarterly. These quarterly evolutions close the normally locked open essential service water supply manual isolation valve, but Technical Specification action statements have not been entered appropriately.

The inspectors brought up their concerns to the licensee and the licensee documented Condition Report 113304, completed a past operability review, and created actions to develop a license amendment request to add a specific Technical Specification condition and submit for NRC approval. Although the licensee did not always recognize that turbine-driven auxiliary feedwater was inoperable with one essential service water supply line isolated, no instances were identified where the essential service water supplies to the turbine-driven auxiliary feedwater pump were individually isolated for more than their Technical Specification allowed outage timebe in Mode 3 within 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br />. The licensee's immediate corrective actions included entering Condition Report 113304 into the corrective action program and incorporating a note on operations turnover documents to temporarily postpone applicable portions of the operations quarterly tasks.

Analysis.

The failure to ensure the auxiliary feedwater system design basis was adequately represented in the Technical Specification Bases was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is associated with the design control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, if left uncorrected, the finding could become a more significant safety concern because the Technical Specification Bases explicitly allowed the isolation of an essential service water supply to the turbine-driven auxiliary feedwater pump without entry into the appropriate Technical Specification action statement and the isolation valve could have been left in the closed position for longer than its Technical Specification allowed outage time (be in Mode 3 within 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br />). The inspectors evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined this finding is not a deficiency affecting the design or qualification of a mitigating SSC that maintained its operability or functionality; the finding does not represent a loss of system and/or function; the finding does 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 does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Therefore, the inspectors determined the finding was of very low safety significance (Green).

The inspectors determined that the finding has a problem identification and resolution cross-cutting aspect in the area of evaluation because the organization did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, during evaluation of Condition Report 111808, the issues were not thoroughly investigated according to their safety significance, and the auxiliary feedwater system design basis was not adequately explored. This issue is indicative of current performance because the evaluation of Condition Report 111808 in May 2017 was a reasonable opportunity for the licensee to identify that the Technical Specification Bases was inadequate [P.2].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that the design basis, is correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, until May 25, 2017, measures were not established to assure that the design basis, is correctly translated into specifications, drawings, procedures, and instructions.

Specifically, the auxiliary feedwater design basis, as outlined in the Updated Safety Analysis Report, was not correctly translated into Section 3.7.5 of the Technical Specification Bases, and the Technical Specification Bases explicitly and incorrectly stated that inoperability of a single suction isolation valve from essential service water to the turbine-driven auxiliary feedwater train does not render the turbine-driven auxiliary feedwater train inoperable. Immediate corrective actions included entering Condition Reports 113304 and 116852 into the corrective action program and incorporating a note on operations turnover documents to temporarily postpone applicable portions of the operations quarterly tasks. This violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000482/2017003-02, Failure to Ensure the Design Basis was Adequately Represented in the Technical Specification Bases.

.2 Enforcement Action EA-17-170, Enforcement Discretion for Tornado-Generated Missile

Protection Noncompliances

Description.

Title 10 CFR Part 50, Appendix A, General Design Criteria for Nuclear Power Plants, Criterion 2, Design Bases for Protection Against Natural Phenomena, states, in part, that SSCs important to safety shall be designed to withstand the effects of natural phenomena, such as tornadoes. Criterion 4, Environmental and Dynamic Effects Design Basis, states, in part, that SSCs important to safety shall be appropriately protected against dynamic effects including missiles that may result from events and conditions outside the nuclear power unit. Section 3.5.3.1, Tornado Missile Barrier Design Procedures, of the Updated Safety Analysis Report describes the parameters of tornado-resistant structures including wall thickness and concrete strength. Table 3.3-1, Tornado-Resistant Buildings and Enclosures, of the Updated Safety Analysis Report lists the structures that are designed to withstand tornado missile impact.

On February 7, 2017, the NRC issued Enforcement Guidance Memorandum (EGM)15-002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance, Revision 1 (ADAMS Accession Number ML16355A286). The EGM referenced a bounding generic risk analysis performed by the NRC staff that concluded that tornado missile vulnerabilities pose a low risk significance to operating nuclear plants. Because of this, the EGM described the conditions under which the NRC staff may exercise enforcement discretion for noncompliance with the current licensing basis for tornado-generated missile protection. Specifically, if the licensee could not meet the technical specification required actions within the required completion time, the EGM allows the staff to exercise enforcement discretion provided the licensee implements initial compensatory measures prior to the expiration of the time allowed by the limiting condition for operation. The compensatory actions should provide additional protection such that the likelihood of tornado missile effects are lessened. The EGM then requires the licensee to implement more comprehensive compensatory measures within approximately 60 days of issue discovery. The compensatory measures must remain in place until permanent repairs are completed, or until the NRC dispositions the non-compliance in accordance with a method acceptable to the NRC such that discretion is no longer needed. Because EGM 15-002 listed Wolf Creek as a Group A plant, enforcement discretion will expire on June 10, 2018.

Section 10.3, Main Steam Supply System, of the Updated Safety Analysis Report describes the safety function of the Atmospheric Relief Valves (ARVs) and the main steam safety valves (MSSVs). Specifically, MSSVs provide overpressure protection in accordance with the ASME Section III code requirement for the secondary side of the steam generators and the main steam piping. The ARVs provide for controlled removal of reactor decay heat during normal reactor cooldown when the main steam isolation valves are closed or the turbine bypass system is not available. Safety design basis one of this section further states, The safety-related portion of the [main steam supply system] is protected from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).

On September 7, 2017, the licensee identified that there was no retrievable analysis proving that a single tornado driven design basis missile is not capable of affecting more than two ARVs. This vulnerability was identified as part of the licensees review of operating experience from Callaway Plant regarding potential nonconforming condition regarding tornado generated missile effects on MSSVs and ARVs. This issue was entered into the corrective action program as Condition Report 115590.

As a result of this issue, the licensee declared all ARVs and MSSVs inoperable, complied with the applicable technical specification action statements, initiated Condition Report 115590, invoked the EGM discretion guidance, implemented initial compensatory measures, and returned the SSCs to an operable-degraded/non-conforming status. The licensee instituted compensatory measures intended to reduce the likelihood of tornado missile effects. These included verifying that guidance was in place for severe weather procedures, abnormal and emergency operating procedures, and FLEX support guidelines, verifying that training on these procedures was current, and verifying that a heightened level of awareness of the vulnerability was established.

Enforcement.

Technical Specification 3.7.1 requires, in part, that five MSSVs per steam generator shall be operable in Modes 1, 2, and 3. Technical Specification 3.7.1.C requires that, for one or more steam generators with greater than 4 MSSVs inoperable, 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 be in Mode 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to the above, prior to September 7, 2017, one or more steam generators with greater than 4 MSSVs were not operable, and action was not initiated 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 be in Mode 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Specifically, the discharge piping to atmosphere for MSSVs was not designed to withstand the effects of natural phenomena, such as tornadoes.

The licensee initiated a Condition Report, invoked the enforcement discretion guidance, implemented initial compensatory measures, and returned the SSCs to an operable-degraded/non-conforming status. The inspectors verified through inspection sampling that the EGM 15-002 criteria were met and that the issue was documented in Condition Report 115590. Therefore, EGM 15-002 enforcement discretion was applied to the required shutdown actions associated with this technical specification.

Technical Specification 3.7.4 requires, in part, that four ARV lines shall be operable in Modes 1, 2, and 3. Technical Specification 3.7.4.C requires that, for three or more required ARV lines inoperable for reasons other than excessive leakage, restore all but two required ARV lines to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or 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 be in Mode 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to the above, prior to September 7, 2017, four ARV lines were not operable, and action was not initiated to restore all but two required ARV lines to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or 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 be in Mode 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Specifically, the discharge piping to atmosphere for ARVs was not designed to withstand the effects of natural phenomena, such as tornadoes.

The licensee initiated a Condition Report, invoked the enforcement discretion guidance, implemented initial compensatory measures, and returned the SSCs to an operable-degraded/non-conforming status. The inspectors verified through inspection sampling that the EGM 15-002 criteria were met and that the issue was documented in Condition Report 115590. Therefore, EGM 15-002 enforcement discretion was applied to the required shutdown actions associated with this technical specification.

1R19 Post-Maintenance Testing

a. Inspection Scope

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

• July 18, 2017, train A safety injection pump planned maintenance

• July 19, 2017, train A containment spray pump planned maintenance

• August 1, 2017, train B essential service water pump planned maintenance

• August 8, 2017, auxiliary feedwater isolation valves to steam generators A and D (ALHV0007 and ALV0035) planned maintenance

• August 23, 2017, diesel fire pump planned maintenance

• August 28, 2017, turbine driven auxiliary feedwater discharge control valve (ALHV0006) planned maintenance

• September 14, 2017, train B emergency diesel generator planned maintenance

• September 21, 2017, train A 125 volt direct current battery charger planned maintenance 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 eight 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 three 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:

Other surveillance tests:

• August 21, 2017, STS IC-803A, 4 KV Undervoltage - Grid Degraded Voltage Channel Calibration NB01 Bus

• August 23, 2017, STS KJ-013A, Hot Restart of EDG NE01

• September 5, 2017, STS EM-100B, Safety Injection Pump B Inservice Pump Test 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 tests satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected SSCs following testing.

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

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors observed emergency preparedness drills on July 18, 2017, and September 19, 2017, to verify the adequacy and capability of the licensees assessment of drill performance. The inspectors reviewed the drill scenarios, observed the drills from the simulator, technical support center, and emergency offsite facility, and attended the post-drill critiques. The inspectors verified that the licensees emergency classifications, off-site notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the licensee in the post-drill critique and entered into the corrective action program for resolution.

These activities constituted completion of two emergency preparedness drill observation samples, as defined in Inspection Procedure 71114.06.

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 Mitigating Systems Performance Index: Emergency AC Power Systems (MS06)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the period of September 1, 2016, through June 30, 2017, to verify the accuracy and completeness of the reported data. 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 mitigating system performance index for emergency AC power systems, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index: High Pressure Injection Systems (MS07)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the period of September 1, 2016, through June 30, 2017, to verify the accuracy and completeness of the reported data. 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 mitigating system performance index for high pressure injection systems, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index: Cooling Water Support Systems (MS10)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the period of September 1, 2016, through June 30, 2017, to verify the accuracy and completeness of the reported data. 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 mitigating system performance index for cooling water support systems, 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 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected one issue for an in-depth follow-up:

• On June 30, 2016, a team of NRC inspectors completed a biennial problem identification and resolution inspection in which they identified that individuals in some groups within the security department may not feel free to raise concerns, or may fear retaliation if they were to raise concerns. The 2016 team also noted that a survey administered in late 2015 had provided earlier indications of this lack of a strong safety-conscious work environment (SCWE), but actions taken in response to that survey had yet to be effective.

The inspectors reviewed the licensees actions in response to the June 30, 2016, observations, assessing the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors reviewed the licensees prioritization of corrective actions and evaluated whether planned or in-progress actions appeared adequate to correct the condition. To evaluate the effectiveness of the corrective actions already implemented, the inspectors interviewed four individuals from security access screening and security support, ten individuals from maintenance support, and several managers and supervisors.

These activities constituted completion of one annual follow-up sample as defined in Inspection Procedure 71152.

b. Discussion The inspectors noted that some SCWE challenges identified during the 2016 problem identification and resolution inspection were ongoing, but that in-progress management actions appeared adequate to correct these work environment challenges. These in-progress improvements appeared to largely be the result of a reorganization of the security department. Actions taken through the corrective action program to directly address the SCWE challenges identified by the 2016 teamwhich were subsequently confirmed by the results of a nuclear safety culture assessmentwere to brief the nuclear safety culture monitoring panel on the results of the assessment. In most cases, these briefings were completed and the actions were closed with no follow-on actions to correct the issue. The team determined that this alone would likely have been inadequate to make progress in addressing the SCWE challenges in the security department.

Although the currently in-progress actions did not appear to be driven by the CAP, the inspectors concluded that these actions were likely to be successful. However, a two-year delay from the indications of work environment challenges provided by the 2015 survey to successful implementation of corrective actions indicated a challenge to prioritization of corrective actions within the corrective action program.

The inspectors also identified significant work environment challenges in the maintenance support group that could potentially affect the safety-related aspects of their work and could be considered as a precursor to a chilled environment. During focus group discussions, nearly all of the participants expressed disappointment with the amount of resources allocated to their group including a lack of training, tools, experience, and staffing. Much of the discussion involved a dissatisfaction with the handling of several industrial safety issues and subsequent loss of confidence in the corrective action program when these issues were not addressed after attempts were made to resolve them by initiating condition reports. Furthermore, several personnel interviewed by the inspectors stated that individuals had stopped bringing up issues because they were concerned that they would be blacklisted or suffer other adverse consequences if they continued to raise concerns, or if they were to escalate them to a higher organizational level. Several individuals indicated a willingness to raise important concerns, including nuclear safety concerns, despite this fear of retaliation. Additionally, interviewees stated a willingness to alert the control room to any problems identified inside the power block. However, the team determined that an unwillingness to raise other concerns indicated significant challenges to the SCWE in the maintenance support group. While much of the work performed by maintenance support occurs outside the fence and may not have an obvious impact on nuclear safety or the power block, certain tasks performed by members of this team, such as erecting scaffolding or assisting with maintenance can potentially impact safety related equipment. Individuals working at nuclear power plants should feel comfortable raising safety concerns and escalating issues of concern regardless of perceived impact to nuclear safety because individuals may not realize that their concern impacts nuclear safety. The licensee initiated condition report 116792 to track the resolution of these issues.

c. Findings

No findings were identified.

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

(Closed) Licensee Event Report (LER) 05000482/2016-002-00, Loss of Switchyard Bus Results in Emergency Diesel Generator Actuation

a. Inspection Scope

On November 16, 2016, a fault occurred that isolated the east switchyard bus from the train A safety-related 4160 volt alternating current bus NB01, while the Wolf Creek Nuclear Generating Station was in Mode 5 with the reactor coolant system filled and a bubble in the pressurizer. During refueling outage 21, a modification to transformer 7 allowed the offsite power through transformer 7 to bus NB01 to be fed from either the east or west switchyard busses through two different breakers (345-80 or 345-90). After the loss of the east switchyard bus, the second breaker unexpectedly tripped, which resulted in a loss of offsite power to bus NB01. An undervoltage condition was detected on bus NB01, which caused the train A emergency diesel generator to start and power bus NB01 as designed. All other systems functioned as expected.

The licensee documented condition report 109467, completed a cause evaluation, and updated the Wolf Creek substation procedure to include steps that require work instructions for post maintenance testing of current transformer wiring configuration to ensure independent verification of wiring terminations. The inspectors reviewed this issue and determined that this issue constituted a self-revealed more-than-minor non-cited violation.

This LER is closed.

b. Findings

Failure to Verify Equipment or Systems are Capable of Performing Their Intended Design Function Following Maintenance

Introduction.

The inspectors reviewed a Green, self-revealed non-cited violation of Technical Specification 5.4.1.a for the licensees failure to ensure that maintenance that can affect the performance of safety-related equipment was properly pre-planned and performed in accordance with written procedures, documented, instructions, or drawings appropriate to the circumstances. Specifically, the licensee failed to verify that the wiring in the transformer 7 primary differential protective relay was landed on the correct termination point, and as a result, the station experienced an unplanned loss of normal offsite power to bus NB01, the train A Class 1E electrical bus.

Description.

On November 16, 2016, at approximately 9:09 p.m., a fault occurred that isolated the east switchyard bus from the train A safety-related 4160 volt alternating current bus NB01, while the Wolf Creek Nuclear Generating Station was in Mode 5 with the reactor coolant system filled and a bubble in the pressurizer. During refueling outage 21, a modification to transformer 7 allowed the offsite power through transformer 7 to bus NB01 to be fed from either the east or west switchyard busses through two different breakers (345-80 or 345-90). After the loss of the east switchyard bus, the second breaker unexpectedly tripped, which resulted in a loss of offsite power to NB01.

An undervoltage condition was detected on bus NB01, which caused the train A emergency diesel generator to start and power bus NB01 as designed. All other systems functioned as expected.

Westar, the substation owner, determined that the initial fault was caused by a mouse on the 13-4 circuit at Wolf Creek. The 13-4 relay and breaker cleared the fault and coordinated with all upstream devices. Approximately 5.5 seconds after the initial fault, a second fault occurred in transformer 6.

The transformer 7 digital differential relay scheme provides a standard configuration with primary and secondary protective relays, each with the capability of isolating transformer 7. Troubleshooting activities focused on the reason why the primary relay tripped and the secondary relay did not trip. Westar technicians identified a jumper on the transformer 7 primary differential relay current transformer circuit that had been improperly landed. The jumper was designed to run from the neutral circuit of one current transformer to the neutral circuit of the other. However, Westar Energy technicians had incorrectly landed the jumper from the neutral of the first current transformer onto the C phase of the other. This allowed current from the transformer 6 fault event to be detected in the transformer 7 primary differential relay circuit.

The inspectors reviewed the cause evaluation completed by the licensee, which determined that the direct cause of this event was the wiring in the transformer 7 primary differential protective relay was landed on the incorrect termination point. This cause is supported by the fact that this incorrect termination allowed additional current to be introduced onto the C phase relay circuit, which initiated the trip circuit actuation.

The inspectors also reviewed corrective actions associated with the root cause evaluation for the unplanned plant shutdown, loss of offsite power, and Notification of Unusual Event declaration that occurred on January 13, 2012. An Augmented Inspection Team was chartered to review the circumstances surrounding the loss of offsite power event and Notification of Unusual Event declarationan issue of Yellow safety significance was identified. The event from January 13, 2012, involved equipment owned by Wolf Creek (startup transformer XMR01), with work being performed by Wolf Creek contractors. The November 16, 2016, event involved equipment owned by Westar (transformer 7). While inspectors acknowledge that the two events from January 13, 2012, and November 16, 2016, are not exactly the same, the inspectors noted that they are similar in that they both involved the modification of current transformer wiring associated with transformers that provide power to train A and B engineered safety function transformers (XNB01 and XNB02, respectively), which supply train A and B Class 1E electrical busses NB01 and NB02, respectively. The inspectors did not determine that the 2012 event actions were causal to the 2016 event; however, the inspectors noted similarities between the identified causes.

Procedure AP 21C-001, Wolf Creek Substation, establishes responsibilities and defines necessary interfaces and communications for the operational control, coordination and maintenance necessary to ensure Wolf Creek Substation protection, safety and reliability. The inspectors reviewed the licensees assessment associated with the 2016 event and concluded that the substation work control process requirements in procedure AP 21C-001 were not adequately met. Specifically, step 6.2.5.1 states, in part, that following preventive or corrective maintenance work, appropriate post-maintenance inspections, checks, and/or testing shall be performed to verify that affected equipment or systems (primary and secondary differential relay circuitry) are capable of performing their intended design function.

The wiring error on the primary differential protective relay was corrected and its functionality was verified. The secondary differential protective relay wiring was also verified to be correct. The east switchyard bus, transformer 7, and its differential relays were all restored to service. The licensee documented the event in LER 2016-002-00 and Condition Reports 109467 and 116849. The licensee also updated procedure AP 21C-001 to include additional detail and steps that require work instructions for post maintenance testing of current transformer wiring to ensure independent verification of wiring terminations.

Analysis.

The licensees failure to verify that the primary and secondary differential relay circuitry is capable of performing its intended design function following maintenance was a performance deficiency. The performance deficiency was more than minor because it affected the design control attribute of the Mitigating Systems 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 licensee failed to verify that the wiring terminations for the primary differential protective relay for transformer 7 were installed correctly, leading to the isolation of transformer 7, resulting in an unplanned loss of offsite power to NB01, the train A Class 1E electrical bus. The inspectors evaluated the finding using Exhibit 3, "Mitigating Systems Screening Questions," of Inspection Manual Chapter 0609, Appendix G, Attachment 1, "Shutdown Operations Significance Determination Process Phase I Initial Screening and Characterization of Finding," and Appendix G, "Shutdown Operations Significance Determination Process," both issued May 9, 2014. The inspectors determined this finding is a deficiency affecting the design or qualification of a mitigating SSC, and the SSC maintained its operability or functionality. Therefore, the inspectors determined the finding was of very low safety significance (Green).

The inspectors determined that the finding has a human performance cross-cutting aspect in the area of resources because leaders did not ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, leaders did not ensure adequate procedures were available to support successful work performance including necessary standards for verifying wiring circuitry terminations such that the loss of power to the NB01 Class 1E electrical bus would not have occurred. This issue is indicative of current performance because the issue occurred in the last three years [H.1].

Enforcement.

Technical Specification 5.4.1.a requires, in part, that procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2. Section 9.a of Appendix A to Regulatory Guide 1.33, Revision 2, requires, in part, that maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures, documented, instructions, or drawings appropriate to the circumstances. The licensee established Procedure AP 21C-001, Wolf Creek Substation, to meet te Regulatory Guide 1.33 requirement. Section 6.2.5.1 of Procedure AP 21C-001 requires, in part, that following preventive or corrective maintenance work, appropriate post-maintenance inspections, checks, and/or testing shall be performed to verify that affected equipment or systems are capable of performing their intended design function. Contrary to the above, until November 17, 2016, following preventive or corrective maintenance work, appropriate post-maintenance inspections, checks, and/or testing was not performed to verify that affected equipment or systems are capable of performing their intended design function.

Specifically, following maintenance work associated with the primary and secondary differential relay circuitry, post-maintenance inspections, checks, and/or testing were not adequately performed to verifying that the normal power to the NB01 Class 1E electrical bus was capable of performing its intended design function. As a result, the licensee experienced an unplanned loss of normal offsite power to bus NB01, the train A Class 1E electrical bus. The licensee took the immediate corrective actions of working with Westar to ensure the protective relay wiring termination issue for transformer 7 was identified and corrected, and that transformer 7 was returned to service. The licensee entered the issue into the corrective action program as Condition Reports 109467 and 116849. This violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000482/2017003-03, Failure to Verify Equipment or Systems are Capable of Performing Their Intended Design Function Following Maintenance.

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

4OA6 Meetings, Including Exit

Exit Meeting Summary

On July 6, 2017, a regional inspector briefed Mr. A. Servaes, Regulatory Exam Author, of the results of the licensed operator requalification program inspection. The licensee representative acknowledged the results presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On August 30, 2017, regional inspectors presented the results of the problem identification and resolution inspection to Mr. C. 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.

On October 23, 2017, the resident inspectors presented the inspection results to Mr. J. McCoy, Vice President, Engineering, 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.

On November 7, 2017, the resident inspectors presented the inspection results to Mr. D. Hall, Manager, Stategic Projects, 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.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Adams, Supervisor, Radiation Protection

J. Ashley, Supervisor, System Engineering

R. Audano, Superintendent, Maintenance

R. Ayers, Supervisor, Radiation Protection

T. Baban, Manager, Engineering Programs

D. Bowers, Manager, Maintenance

W. Brandt, Shift Manager

K. Clark, Technician, Fire Protection

M. Corbin, Superintendent, Security Operations

J. Cuffe, Supervisor, Radiation Protection

T. East, Superintendent, Emergency Planning

J. Edwards, Manager, Operations

R. Fincher, Manager, Quality

R. French, Supervisor, Radiation Protection

J. Fritton, Oversight

G. Fugate, Director, Plant Support

L. Fure, Master Technician, Radiation Protection

A. Gilliam, Technician, Radiation Protection

C. Gross, Manager, Chemistry

C. Hafenstine, Manager, Regulatory Affairs

D. Hall, Manager, Strategic Projects

A. Heflin, President and Chief Executive Officer

P. Herrman, Manager, Design Engineering

R. Hobby, Licensing Engineer

J. Isch, Superintendent, Operations Work Controls

K. Jay, Manager, Radiation Protection

R. Jung, Instructor, Fire Protection

J. Knust, Licensing Engineer

R. Lane, Manager, Integrated Plant Scheduling

B. Lee, Superintendent, Technical Training

D. Mand, Director, Engineering

J. McCoy, Vice President, Engineering

W. Muilenburg, Supervisor, Licensing

E. Peterson, Employee Concerns Program Coordinator

C. Reasoner, Site Vice President

J. Schepers, Supervisor, Radiation Protection

A. Servaes, Licensed Instructor

M. Skiles, Manager, Security

T. Slenker, Supervisor, Operations Support

S. Smith, Plant Manager

L. Stone, Licensing Engineer

A. Stull, Vice President and Chief Administrative Officer

J. Suter, Supervisor, Fire Protection

M. Tate, Superintendent, Security Operations

J. Yunk, Manager, Training

NRC Personnel

D. Proulx, Senior Project Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000482/2017003-01 NCV Programmatic Failure to Scope Floor Drain Function within the Maintenance Rule Monitoring Program (Section 1R12)

05000482/2017003-02 NCV Failure to Ensure the Design Basis was Adequately Represented in the Technical Specification Bases (Section 1R15)

05000482/2017003-03 NCV Failure to Verify Equipment or Systems are Capable of Performing Their Intended Design Function Following Maintenance (Section 4OA3)

Closed

05000482/2016-002-00 LER Loss of Switchyard Bus Results in Emergency Diesel Generator Actuation (4OA3)