IR 05000298/2016002

NRC Integrated Inspection Report 05000298/2016002, April 1, 2016 Through June 30, 2016

ML16211A197
Person / Time
Site:	Cooper
Issue date:	07/29/2016
From:	Greg Warnick NRC/RGN-IV/DRP/RPB-C
To:	Limpias O Nebraska Public Power District (NPPD)
Greg Warnick
References
IR 2016002
Download: ML16211A197 (52)

Text

UNITED STATES uly 29, 2016

SUBJECT:

COOPER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000298/2016002

Dear Mr. Limpias:

On June 30, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Cooper Nuclear Station. On July 13, 2016, the NRC inspectors discussed the results of this inspection with you and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

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

All of these findings involved violations of NRC requirements. 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 Cooper Nuclear 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 Cooper Nuclear 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/

Greg Warnick, Branch Chief Project Branch C Division of Reactor Projects Docket No. 50-298 License No. DPR-46

Enclosure:

Inspection Report 05000298/2016002 w/ Attachment: Supplemental Information

REGION IV==

Docket: 05000298 License: DPR-46 Report: 05000298/2016002 Licensee: Nebraska Public Power District Facility: Cooper Nuclear Station Location: 72676 648A Ave Brownville, NE Dates: April 1 through June 30, 2016 Inspectors: P. Voss, Senior Resident Inspector C. Henderson, Resident Inspector J. Kirkland, Senior Operations Engineer P. Elkmann, Senior Emergency Preparedness Inspector G. Guerra, Emergency Preparedness Inspector N. Greene, Health Physics Inspector C. Young, Senior Project Engineer J. Melfi, Project Engineer, DRP/D Approved Greg Warnick By: Chief, Project Branch C Division of Reactor Projects-1- Enclosure

SUMMARY

IR 05000298/2016002; 04/01/2016 - 06/30/2016; Cooper Nuclear Station; Maintenance

Effectiveness, Post-Maintenance Testing, and Follow-up of Events and NOEDs.

The inspection activities described in this report were performed between April 1 and June 30, 2016, by the resident inspectors at the Cooper Nuclear Station and inspectors from the NRCs Region IV office. Three findings of very low safety significance (Green) are documented in this report. All of these findings involved violations of NRC requirements. 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 reviewed a self-revealed, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, for the licensees failure to verify the adequacy of design of the high pressure coolant injection auxiliary lube oil pump 125 Vdc starter circuit.

Specifically, in 1984, the licensee modified the design of the starter circuit and eliminated a resistor that served to protect the circuit from shorting due to indication light bulb failures.

As a result, on April 26, 2016, a shorted light bulb resulted in the loss of power to the auxiliary lube oil pump, rendering the high pressure coolant injection system inoperable and unavailable. Immediate corrective actions included replacing the light socket and blown fuse and changing out the nonessential light bulb with an essential bulb. This event was entered into the licensees corrective action program as Condition Report CR-CNS-2016-02318, and the licensee initiated a root cause evaluation to investigate the failure.

The licensees failure to verify the adequacy of design of the high pressure coolant injection auxiliary lube oil pump starter circuit in accordance with 10 CFR Part 50, Appendix B,

Criterion III, was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment performance 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. Specifically, at the time the modification was installed, the licensee had not taken sufficient actions to ensure that the electrical circuit was protected from light bulb shorting failures, resulting in the high pressure coolant injection system ultimately being rendered inoperable. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, inspectors determined that the finding required a detailed risk evaluation because it represented a loss of the system and function of high pressure coolant injection. The inspectors determined that the finding was of very low safety significance (Green) through performing a detailed risk evaluation. A cross-cutting aspect was not assigned to this finding because the performance deficiency occurred in 1984, and therefore, is not indicative of current licensee performance (Section 4OA3).

Cornerstone: Barrier Integrity

Green.

The inspectors identified a non-cited violation of Technical Specification 3.6.1.3,

Primary Containment Isolation Valves, for the licensees failure to maintain traversing in-core probe B ball valve, a primary containment isolation valve, operable for its containment isolation function. Specifically, on May 5, 2016, from 5:20 a.m. until 1:08 p.m., the licensee failed to maintain the traversing in-core probe B ball valve operable or isolate its flow path within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of indications that the mechanical in-shield limit switch had failed. This failure prevented the ball valve from performing its containment isolation function. The licensee took immediate corrective actions upon discovery to restore compliance with Technical Specification 3.6.1.3 by de-energizing the ball valves solenoid operating valve, causing it to close. The licensee entered this deficiency into their corrective action program for resolution as Condition Report CR-CNS-2016-03665.

The licensees failure to maintain the traversing in-core probe B ball valve, a primary containment isolation valve, operable for its containment isolation function, in violation of Technical Specification 3.6.1.3, was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases and that the radiological barrier functionality of containment is maintained. Specifically, the traversing in-core probe B ball valve was unable to perform its primary containment isolation function with a failed mechanical in-shield limit switch. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), and heat removal components; and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The finding had a cross-cutting aspect in the area of human performance associated with conservative bias because the licensee failed to use decision-making practices that emphasized prudent choices over those that were simply allowable and failed to ensure proposed actions were determined to be safe in order to proceed, rather than unsafe in order to stop. Specifically, the licensee failed to validate the assumption that the traversing in-core probe B ball valve would fulfill its containment isolation function with a failed mechanical in-shield limit switch, and failed to validate the degraded condition prior to exceeding the 4-hour completion time of Technical Specification 3.6.1.3 (Section 1R12). [H.14]

Multiple Cornerstones: Mitigating Systems and Barrier Integrity

Green.

The inspectors identified two examples of a non-cited violation of Technical Specification 5.4.1.a, associated with the licensees failure to perform required post-maintenance testing for safety-related ventilation systems in accordance with documented instructions, prior to system restoration. Specifically, the licensee failed to follow work order instructions contained in Work Orders 5062878 and 5065112 for (1) performing surveillance testing to measure the airflow of emergency diesel generator supply fan coil unit HV-DG-1C following maintenance, and (2) performing leak testing of a newly created control room ventilation boundary penetration. Corrective actions included performing the required surveillance test for the diesel generator ventilation unit, retesting the control room penetration in accordance with the procedure, and initiating site-wide communications discussing the errors and reemphasizing procedural adherence. The licensee entered these deficiencies into their corrective action program for resolution as Condition Reports CR-CNS-2016-02207 and CR-CNS-2016-02232.

The licensees failure to perform required post-maintenance testing for safety-related ventilation systems, in accordance with documented instructions, was a performance deficiency. This performance deficiency was associated with multiple cornerstones. The first example of the performance deficiency was more than minor, and therefore a finding, because it was associated with the human performance 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. Specifically, the failure to measure supply fan coil unit HV-DG-1C airflow resulted in delayed identification that the maintenance had resulted in degraded flow through the ventilation unit. The second example of the performance deficiency was more than minor, and therefore a finding, because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases and that the radiological barrier functionality of the control room is maintained. Specifically, the licensees failure to follow post-maintenance testing instructions resulted in a challenge to the operability of the newly created control room boundary penetration seal. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green) because it did not represent a design or qualification deficiency; did not represent a loss of safety function; did not represent a loss of a single train for greater than its technical specification allowed outage time; did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating events; did not represent an actual open containment pathway; and did not involve a reduction in function of hydrogen igniters. The finding had a cross-cutting aspect in the area of human performance associated with work management, because the licensee failed to implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority, including the need for coordination with different work groups or job activities. Specifically, the licensee failed to control, execute, and coordinate safety-related ventilation work activities to ensure all required post-maintenance testing was completed satisfactorily prior to declaring the associated equipment operable (Section 1R19). [H.5]

PLANT STATUS

The Cooper Nuclear Station began the inspection period at full power, where it remained for the rest of the reporting period, except for minor reductions in power to support scheduled surveillances and rod pattern adjustments.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness to Cope with External Flooding

a. Inspection Scope

On June 7, 2016, the inspectors completed an inspection of the stations readiness to cope with external flooding. After reviewing the licensees flooding analysis, the inspectors chose one plant area that was susceptible to flooding:

• Intake structure and service water pump room The inspectors reviewed plant design features and licensee procedures for coping with flooding. The inspectors walked down the selected areas to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether credited operator actions could be successfully accomplished.

These activities constituted one sample of readiness to cope with external flooding, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial Walkdown

a. Inspection Scope

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

• May 9, 2016, Emergency diesel generator 1 jacket water system

• May 10, 2016, Emergency diesel generator 1 starting air system

• May 11, 2016, Emergency diesel generator 1 lube oil system 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 three partial system walkdown 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:

• April 13, 2016, Service water pump area, Fire Area IS-A, Zone 20A

• May 20, 2016, Cable spreading room, Fire Area CB-D, Zone 9A

• June 27, 2016, Battery room 1A, Fire Area CB-A-1, Zone 8E

• June 27, 2016, DC switchgear room 1A, Fire Area CB-A-1, Zone 8H 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.

1R06 Flood Protection Measures

a. Inspection Scope

On May 10, 2016, the inspectors completed an inspection of the stations ability to mitigate flooding due to internal causes. After reviewing the licensees flooding analysis, the inspectors chose one plant area containing risk-significant structures, systems, and components that were susceptible to flooding:

• Reactor building southeast and southwest quads The inspectors reviewed plant design features and licensee procedures for coping with internal flooding. The inspectors walked down the selected areas to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether operator actions credited for flood mitigation could be successfully accomplished.

These activities constituted completion of one flood protection measures sample, as defined in Inspection Procedure 71111.06.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

On May 9, 2016, the inspectors completed an inspection of the readiness and availability of risk-significant heat exchangers. The inspectors reviewed the inspections for the emergency diesel generator 1 and 2 jacket water, lube oil, and intercooler heat exchangers. Additionally, the inspectors walked down the heat exchangers to observe their performance and material condition and verified that the heat exchangers were correctly categorized under the Maintenance Rule and were 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.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On May 18, 2016, the inspectors observed a portion of an annual requalification test for licensed operators. 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

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 room emergency ventilation being out of service and control rod manipulations. The inspectors observed the operators performance of the following activities:

• May 17, 2016, Control room lights dimmed during control room emergency filtration maintenance

• June 24, 2016, Down power and rod pattern adjustment, including the pre-job brief 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 June 23, 2016, the licensee informed the inspector of the following Cooper Nuclear Station operating test results:

• 7 of 7 crews passed the simulator portion of the operating test

• 40 of 40 licensed operators passed the simulator portion of the operating test

• 40 of 40 licensed operators passed the job performance measure portion of the operating test There were no remediations performed for the Cooper Nuclear Station operating tests.

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

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed three instances of degraded performance or conditions of safety-related structures, systems, and components (SSCs):

• April 9, 2016, Emergency diesel generator 1 and 2 bolting torque requirements 10 CFR 50.65(a)(1) monitoring plan

• June 10, 2016, Residual heat removal system motor operated valve testing

• June 22, 2016, Traversing in-core probe system containment isolation valve failure 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 three maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of Technical Specification (TS) 3.6.1.3, Primary Containment Isolation Valves, for the licensees failure to maintain traversing in-core probe (TIP) B ball valve, a primary containment isolation valve, operable for its containment isolation function. Specifically, on May 5, 2016, from 5:20 a.m. until 1:08 p.m., the licensee failed to maintain the TIP B ball valve operable or isolate its flow path within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of indications that the mechanical in-shield limit switch had failed.

Description.

On May 5, 2016, at 5:20 a.m., the licensee was retracting TIP B in accordance with Station Procedure 4.1.4, Traversing In-Core Probe System, Revision 31. During retraction, TIP B failed to stop automatically at its mechanical in-shield limit switch position of 9646 and continued to retract toward the TIP drive mechanism. Additionally, the in-shield light on the TIP B drive control unit failed to illuminate once the limit switch position was passed. These conditions provided indications that the limit switch had failed. The licensee took immediate action to stop TIP B by placing the drive control unit manual switch to off. This action stopped TIP B at position 9628, maintaining it in the chamber shield. The station verified that TIP B was in the fully retracted and shielded position using an evaluation of the radiation levels in the reactor building. Although indications of an equipment failure existed, operations personnel assumed the TIP B ball valve automatic containment isolation function was not impacted, and the valve was maintained open. The basis for the licensee's decision was the assumption that the Group 2 containment isolation signal was not impacted and would have functioned to close the ball valve. The licensee entered this deficiency into their corrective action program (CAP) for resolution as Condition Report CR-CNS-2016-02424.

The licensee commenced validation of the limit switch failure on May 5, 2016, at 12:05 p.m. and quickly confirmed the condition. Next, the licensee attempted to secure TIP B per Station Procedure 4.1.4, and the TIP B ball valve failed to close. Operations personnel still concluded the TIP B ball valve would have closed on the Group 2 signal at this time; however, they initiated a review of the Group 2 isolation logic to verify this assumption. In parallel, the licensee identified an alternate method of de-energizing the TIP B ball valves solenoid operated valve (SOV), causing it to close at 1:08 p.m. This action restored compliance with TS 3.6.1.3, approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> after the time of identification that the mechanical in-shield limit switch had failed. The licensee then determined the limit switch failure would have prevented the TIP B ball valve from closing on the Group 2 signal. As a result, the licensee declared the TIP B ball valve inoperable; entered TS 3.6.1.3, Required Action A.1; and verified all actions were completed at 1:33 p.m. A manual action from the control room to close the containment isolation shear valve was available during this timeframe per Station Procedure 4.1.4.

The licensee entered this deficiency into their CAP for resolution as CR-CNS-2016-02434.

The inspectors reviewed Condition Reports CR-CNS-2016-02424 and CR-CNS-2016-02434 and the timeline for the failure of the mechanical in-shield limit switch. The inspectors identified that the licensee had failed to meet the requirements of TS 3.6.1.3. Specifically, on May 5, 2016, from 5:20 a.m. until 1:08 p.m., the licensee failed to maintain the TIP B ball valve operable from the time of indication that the mechanical in-shield limit switch had failed until the flow path was successfully isolated.

Initial indications of the failure occurred on May 5, 2016, at 5:20 a.m., when TIP B failed to stop. The inspectors determined that the licensee could have identified the failure to meet TS 3.6.1.3 earlier, and concluded that two factors impacted the licensees ability to recognize the valve inoperability. The first factor was the licensees initial assumption that the TIP B ball valve maintained its containment isolation function with a limit switch failure. The second factor was associated with the licensees failure to commence validation of the limit switch condition commensurate with the safety significance of the TIP ball valve. This safety significance was governed by the 4-hour completion time from TS 3.6.1.3, Required Action A.1, to isolate the TIP B penetration flow path. The licensee entered this deficiency into their CAP for resolution as CR-CNS-2016-03665.

Analysis.

The licensees failure to maintain the TIP B ball valve, a primary containment isolation valve, operable for its containment isolation function, in violation of TS 3.6.1.3, was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases and that the radiological barrier functionality of containment is maintained. Specifically, the TIP B ball valve was unable to perform its primary containment isolation function with a failed mechanical in-shield limit switch. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.),

containment isolation system (logic and instrumentation), and heat removal components; and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The finding had a cross-cutting aspect in the area of human performance associated with conservative bias because the licensee failed to use decision-making practices that emphasized prudent choices over those that were simply allowable and failed to ensure proposed actions were determined to be safe in order to proceed, rather than unsafe in order to stop. Specifically, the licensee failed to validate the assumption that the TIP B ball valve would fulfill its containment isolation function with a failed mechanical in-shield limit switch, and failed to validate the degraded condition prior to exceeding the 4-hour completion time of TS 3.6.1.3, Required Action A.1. [H.14]

Enforcement.

Technical Specification 3.6.1.3, Primary Containment Isolation Valves, requires, in part, Each primary containment isolation valve, except the reactor building-to-suppression chamber vacuum breakers, shall be operable. Contrary to the above, on May 5, 2016, from 5:20 a.m. until 1:08 p.m., the licensee failed to maintain the TIP B ball valve, a primary containment isolation valve, operable. Specifically, the licensee failed to maintain the TIP B ball valve operable or isolate its flow path within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of indications that the mechanical in-shield limit switch had failed, preventing the valve from performing its containment isolation function. The licensee took immediate corrective actions when the valve inoperability was recognized to restore compliance with TS 3.6.1.3 by isolating the affected penetration flow path. Because this violation was of very low safety significance (Green) and was entered into the licensees corrective action program as Condition Report CR-CNS-2016-03665, this violation is being treated as a non-cited violation (NCV) in accordance with Section 2.3.2.a of the Enforcement Policy.

(NCV 05000298/2016002-01, Failure to Meet Technical Specification Requirements for Traversing In-Core Probe B Ball Valve)

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed three 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 8, 2016, Emergency diesel generator 1 maintenance window

• April 12, 2016, Residual heat removal service water booster pump A unavailable during maintenance

• April 19, 2016, High pressure coolant injection maintenance window 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.

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

• April 23, 2016, Unplanned limiting condition for operation entry for service water pump B low gland water flow

• April 27, 2016, Unplanned high pressure coolant injection limiting condition for operation for loss of control power to the auxiliary lube oil pump 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 structures, systems, and components.

These activities constituted completion of five 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 six operability determinations that the licensee performed for degraded or nonconforming structures, systems, or components (SSCs):

• April 5, 2016, Operability determination of 10-inch high pressure coolant injection high energy line break scenario in the reactor building southwest quad

• April 9, 2016, Operability determination of missed post-maintenance test following emergency diesel generator 1 fan coil unit maintenance

• April 12, 2016, Operability determination of emergency diesel generator 1 diesel stack and fill connection corrosion

• April 20, 2016, Operability determination of SGT-DPIC-546 standby gas treatment system flow controller failure

• April 22, 2016, Operability determination of high pressure coolant injection outboard steam isolation valve HPCI-MOV-16 when opening starter rack panel door EE-STR-125HPCI MO16 at power

• May 12, 2016, Operability determination of emergency diesel generator 1 fan coil unit degraded performance trend The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability of the degraded SSC.

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

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

On June 7, 2016, the inspectors reviewed a temporary modification to Surveillance Procedure 6.HV.105, Control Room Envelope Pressurization and CREFS Flow Test, a procedural change to allow only one pressure equalization damper to be open during testing, which affected risk-significant structures, systems, and components (SSCs).

The inspectors verified that the licensee had installed this temporary modification in accordance with technically adequate design documents. The inspectors verified that this modification did not adversely impact the operability or availability of affected SSCs.

The inspectors reviewed design documentation and plant procedures affected by the modification to verify the licensee maintained configuration control.

These activities constituted completion of one sample of temporary modifications, as defined in Inspection Procedure 71111.18.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed seven post-maintenance testing activities that affected risk-significant structures, systems, or components (SSCs):

• April 20, 2016, Replacement of diesel generator lube oil DGLO-CV-10CV gaskets

• April 21, 2016, Alternate shutdown panel high pressure coolant injection controller repair

• April 22, 2016, Increase in emergency diesel generator 1 heating, ventilation, and air conditioning HV-DG-1C airflow

• April 22, 2016, FLEX penetration core boring in the cable spreading room

• April 26, 2016, High pressure coolant injection EE-STR-250 Vdc ALOP 27 relay replacement

• May 24, 2016, Service water pump B maintenance

• May 26, 2016, Residual heat removal flange X39B work 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 seven post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.

b. Findings

Introduction.

The inspectors identified two examples of a Green, non-cited violation (NCV) of Technical Specification (TS) 5.4.1.a, associated with the licensees failure to perform required post-maintenance testing (PMT) for safety-related ventilation systems in accordance with documented instructions, prior to system restoration. Specifically, the licensee failed to follow work order (WO) instructions contained in WOs 5062878 and 5065112 for

(1) performing surveillance testing to measure the airflow of emergency diesel generator (EDG) supply fan coil unit HV-DG-1C following maintenance, and

(2) performing leak testing of a newly created control room envelope (CRE) ventilation boundary penetration.

Description.

The inspectors identified two examples of the licensees failure to perform required PMT activities in accordance with documented maintenance WO instructions.

As a result of breakdowns in the work coordination process and in the execution of the WO instructions, the inspectors determined that the licensee violated the documented instructions contained in WOs 5062878 and 5065112, associated with safety-related ventilation testing. TS 5.4.1.a requires implementation of Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Revision 2, Appendix A, Section 9.a.; which describes the requirements for procedures for performing maintenance, and states, in part, Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.

For these examples, the inspectors determined that multiple work management process barriers failed, which resulted in the restoration of TS equipment without completion of all required PMTs. In both cases, the same engineering personnel failed to follow WO instructions containing required PMT steps. Also, in each case, operations personnel failed to provide the necessary post-work reviews prior to system restoration to ensure that no new deficiencies had been created, the equipment would perform its required function, and the PMT demonstrated operability, consistent with Administrative Procedure 0-CNS-WM-102, Work Implementation and Closeout, Revision 4. Finally, in both cases, the PMT steps were not clearly broken out into separate functions in the WOs to ensure that they were signed off and executed as required. Consistent with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, dated May 6, 2016, because these issues represented multiple examples of the same performance deficiency that shared the same cause and corrective actions, the inspectors determined that they should be documented as a single finding.

Example 1: On April 21, 2016, the inspectors reviewed WO 5062878 for EDG supply fan coil unit HV-DG-1C maintenance to verify all required PMTs were identified and completed satisfactorily. This review was completed after the licensee had completed its review and declared supply fan coil unit HV-DG-1C and EDG 1 operable on April 7, 2016. The inspectors identified Surveillance Procedure 6.1HV.602, Air Flow Test of Fan Coil Unit HV-DG-1C (DIV 1), Revision 8, was not performed as a required PMT in accordance with WO 5062878, Operation 130, Step 2. The inspectors informed the licensee of this deficiency. As an immediate action, the licensee assessed operability of EDG 1 to provide reasonable expectation of operability. The licensees operability assessment estimated supply fan coil unit HV-DG-1C airflow as 31,793 cfm.

On May 5, 2016, in order to correct the deficiency, the licensee performed Surveillance Procedure 6.1HV.602, and the measured airflow was 29,276 cfm. This measured airflow was above the supply fan coil unit HV-DG-1C operability limit, but lower than the previously measured airflow of 30,365 cfm. The estimated airflow had been determined by using the fan laws, which used only differential pressure (DP) of the fan to estimate the airflow, and did not account for all parameters affecting fan airflow, such as changes in duct work resistance or filter DP. The licensee attributed the unexpectedly degraded flow to dirt breaking loose during the cleaning process conducted in WO 5062878. The inspectors determined that engineering personnel executing the PMT had failed to recognize that performance of the surveillance procedure was required by the WO. In addition, the inspectors noted that operations personnel had failed to review the PMT to ensure that appropriate test activities were completed prior to returning the equipment to service. Specifically, no documentation of the surveillance existed because it was not performed, which should have been identified during review by the operations department, consistent with Administrative Procedure 0-CNS-WM-102.

Example 2: On April 18, 2016, the inspectors observed work activities associated with installation of a new conduit penetration that required a breach of the CRE ventilation boundary under WO 5065112. The work required the control room emergency filtration system (CREFS) boundary to be declared inoperable until the penetration was properly sealed. While workers prepared grout prior to sealing the penetration, the inspectors observed the engineer responsible for performing leak testing of the sealed penetration, as he placed a sheet of paper over the unsealed penetration and commented that he felt a suction being drawn on the piece of paper. Following restoration of the penetration to operable status, the inspectors discovered that a PMT had not been documented, despite the fact that Administrative Procedure 0-Barrier, Barrier Control Process, Revision 21, contained detailed instructions for the PMT. Work order 5065112 stated, Perform CRE boundary leak testing and restoration per 0-Barrier, Attachment 11, when core bore is complete and sealed. Administrative Procedure 0-Barrier, Attachment 11, stated, Verify a DP of 0.15 wg for leak test exists per Steps 2.5.1.1 through 2.5.1.5.

The steps that followed included directions for how to take measurements using measuring and test equipment (M&TE), and included lines on which to record these measurements. Interviews with the engineering individual and his supervision revealed that the individual had credited placing the piece of paper over the unsealed hole, and marked the DP measurement steps as not applicable. In addition, the inspectors noted that operations personnel had failed to review the PMT to ensure that appropriate test activities were completed prior to returning the equipment to service. The failure of this barrier was evident in that engineering personnel had failed to mark the PMT activity as complete in the work management system and failed to include any documentation of the test steps that were completed. These issues should have been reviewed and identified as inadequate during review by the operations department. Ultimately, when the test was later correctly performed, operations personnel were required to start CREFS in order to establish a DP of 0.15 wg.

The inspectors determined that in both cases, the licensee failed to control, coordinate, and execute work activities to verify all required PMT activities were completed satisfactorily prior to declaring the affected ventilation systems operable.

Analysis.

The licensees failure to perform required post-maintenance testing for safety-related ventilation systems in accordance with documented instructions was a performance deficiency. Specifically, the licensee failed to follow work order instructions contained in WOs 5062878 and 5065112 for

(1) performing surveillance testing to measure the airflow of emergency diesel generator supply fan coil unit HV-DG-1C following maintenance, and

(2) performing leak testing of a newly created control room ventilation boundary penetration. This performance deficiency was associated with multiple cornerstones. The first example of the performance deficiency was more than minor, and therefore a finding, because it was associated with the human performance 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. Specifically, the failure to measure supply fan coil unit HV-DG-1C airflow resulted in delayed identification that the maintenance had resulted in degraded flow through the ventilation unit. The second example of the performance deficiency was more than minor, and therefore a finding, because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases and that the radiological barrier functionality of the control room was maintained. Specifically, the licensees failure to follow PMT instructions resulted in a challenge to the operability of the newly created control room boundary penetration seal. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green) because it did not represent a design or qualification deficiency; did not represent a loss of safety function; did not represent a loss of a single train for greater than its technical specification allowed outage time; did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating events; did not represent an actual open containment pathway; and did not involve a reduction in function of hydrogen igniters. The finding had a cross-cutting aspect in the area of human performance associated with work management, because the licensee failed to implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority, including the need for coordination with different work groups or job activities. Specifically, the licensee failed to control, execute, and coordinate safety-related ventilation work activities to ensure all required post-maintenance testing was completed satisfactorily prior to declaring the associated equipment operable. [H.5]

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, Procedures for Performing Maintenance. The licensee established WOs 5062878 and 5065112 for performing maintenance on EDG ventilation and the control room ventilation boundary to meet the Regulatory Guide 1.33 requirement. For example (1), Step 2 of WO 5062878 operation 0130, states, in part, Measure flow rate per [surveillance]

procedure 6.1HV.602. For example (2), WO 5065112 states, in part, Perform CRE boundary leak testing and restoration per 0-Barrier Attachment 11 when core bore is complete and sealed.

Contrary to the above, the licensee did not implement required procedures for performing maintenance on safety-related ventilation systems, when:

• (Example 1) On April 7, the licensee failed to implement WO 5062878 when they did not measure flow rate per Surveillance Procedure 6.1HV.602 for Division 1 EDG ventilation following maintenance; and

• (Example 2) On April 18, the licensee failed to implement WO 5065112 when they did not perform CRE boundary leak testing and restoration per 0-Barrier, 11, when core bore activities were complete and sealed following maintenance.

Corrective actions to restore compliance included performing the required surveillance test for the EDG ventilation unit, retesting the control room penetration in accordance with the procedure, and initiating site-wide communications discussing the errors and reemphasizing procedural adherence. Because this violation was of very low safety significance (Green) and was entered into the licensees corrective action program as Condition Reports CR-CNS-2016-02207 and CR-CNS-2016-02232, this violation is being treated as a non-cited violation (NCV) in accordance with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000298/2016002-02, Failure to Follow Work Instructions for Post-Maintenance Testing of Safety-Related Ventilation Systems)

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed five risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the structures, systems, and components (SSCs) were capable of performing their safety functions:

In-service tests:

• May 17, 2016, Emergency diesel generator starting air system check valve surveillance testing Other surveillance tests:

• April 14, 2016, Reactor core isolation cooling system steam line high flow channel functional test

• May 31, 2016, Emergency diesel generator supply fan coil unit HV-DG-1C air flow test, Division 1

• May 31, 2016, 4160V Bus 1F undervoltage relay testing

• June 7, 2016, Emergency diesel generator fuel oil testing surveillances 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 five surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

1EP1 Exercise Evaluation

a. Inspection Scope

The inspectors observed the June 14, 2016, biennial emergency preparedness exercise to verify the exercise acceptably tested the major elements of the emergency plan, and provided opportunities for the emergency response organization to demonstrate key skills and functions. The scenario demonstrated the licensees capability to implement its emergency plan through the simulation of:

• A discharge of toxic gas inside a vital area;

• Loss of an offsite power line to the site because of a nearby tornado;

• The unexpected closure of a main steam isolation valve because of an internal failure; and

• An unisolable steam break outside of the drywell, creating a filtered and monitored radiological release to the environment through the Standby Gas Treatment System (reactor building ventilation) and the Elevated Release Point.

During the exercise the inspectors observed activities in the control room simulator and the following dedicated emergency response facilities:

• Technical Support Center

• Operations Support Center

• Emergency Operations Facility

• Joint Information Center The inspectors focused their evaluation of the licensees performance on the risk-significant activities of event classification, offsite notification, recognition of offsite dose consequences, and development of protective action recommendations.

The inspectors also assessed recognition of, and response to, abnormal and emergency plant conditions, the transfer of decision-making authority and emergency function responsibilities between facilities, onsite and offsite communications, protection of emergency workers, emergency repair evaluation and capability, and the overall implementation of the emergency plan to protect public health and safety, and the environment. The inspectors reviewed the current revision of the facility emergency plan, emergency plan implementing procedures associated with operation of the licensees emergency response facilities, procedures for the performance of associated emergency functions, and other documents as listed in the attachment to this report.

The inspectors attended the post-exercise critiques in each emergency response facility to evaluate the initial licensee self-assessment of exercise performance. The inspectors also attended a subsequent formal presentation of critique items to plant management.

The inspectors discussed with the licensee their discovery of a participant with limited foreknowledge of the exercise scenario and their determination that the participant did not compromise the integrity of the exercise.

The inspectors reviewed the scenarios of previous biennial exercises and licensee drills conducted between September 2014 and May 2016, to determine whether the June 14, 2016, exercise was independent and avoided participant preconditioning, in accordance with the requirements of 10 CFR Part 50, Appendix E, IV.F(2)(g). The inspectors also compared observed exercise performance with corrective action program entries and after-action reports for drills and exercises conducted between September 2014 and May 2016 to determine whether identified weaknesses had been corrected in accordance with the requirements of 10 CFR 50.47(b)(14), and 10 CFR Part 50, Appendix E, IV.F.

These activities constituted one exercise evaluation sample, as defined in Inspection Procedure 71114.01.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspectors performed in-office reviews of Emergency Plan Implementing Procedure 5.7.1, Emergency Classification, Revision 53, effective February 3, 2016, and Emergency Plan, Revision 68, effective March 28, 2016. These revisions:

• Added notes to all emergency action levels with associated time limits to clarify the application of those time limits;

• Implemented a new Emergency Plan Implementing Procedure 5.7.17.1, Dose Assessment (Manual), Revision 0;

• Transferred an emergency preparedness staff position to the site training department; and,

• Updated the licensees Memorandum of Agreement with the State of Nebraska.

These revisions were compared to their previous revisions, to the criteria of NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, to Nuclear Energy Institute Report 99-01, Emergency Action Level Methodology, Revision 5, and to the standards in 10 CFR 50.47(b) to determine if the revisions adequately implemented the requirements of 10 CFR 50.54(q)(3) and 50.54(q)(4).

The inspectors verified that the revisions did not decrease the effectiveness of the emergency plan. This review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, these revisions are subject to future inspection.

These activities constituted completion of two emergency action level and emergency plan change samples, as defined in Inspection Procedure 71114.04.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Training Evolution Observation

a. Inspection Scope

On June 1, 2016, the inspectors observed simulator-based licensed operator requalification training that included implementation of the licensees emergency plan.

The inspectors verified that the licensees emergency classifications, offsite notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the evaluators and entered into the corrective action program for resolution.

These activities constituted completion of one training observation sample, as defined in Inspection Procedure 71114.06.

b. Findings

No findings were identified.

1EP8 Exercise Evaluation - Scenario Review

a. Inspection Scope

The licensee submitted the preliminary exercise scenario for the June 14, 2016, biennial exercise to the NRC on April 14, 2016, in accordance with the requirements of 10 CFR Part 50, Appendix E, IV.F(2)(b). The inspectors performed an in-office review of the proposed scenario to determine whether it would acceptably test the major elements of the licensees emergency plan and provide opportunities for the emergency response organization to demonstrate key skills and functions. The inspectors discussed the preliminary scenario with staff at the Federal Emergency Management Agency (FEMA),

Region VII, to determine whether the preliminary scenario supported the FEMA exercise evaluation objectives.

These activities constituted completion of one scenario evaluation sample, as defined in Inspection Procedure 71114.08.

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 Safety System Functional Failures (MS05)

a. Inspection Scope

For the period of April 1, 2015 through March 31, 2016, the inspectors reviewed licensee event reports (LERs), maintenance rule evaluations, and other records that could indicate whether safety system functional failures had occurred. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, Revision 3, to determine the accuracy of the data reported.

These activities constituted verification of the safety system functional failures performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 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 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.

.3 Reactor Coolant System Total Leakage (BI02)

a. Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system total leakage for the period of April 1, 2015 through March 31, 2016, 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 reactor coolant system leakage performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.4 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspectors reviewed the licensees evaluated exercises, emergency plan implementations, and selected drill and training evolutions, that occurred between October 2015 and March 2016, to verify the accuracy of the licensees data for classification, notification, and protective action recommendation (PAR) opportunities.

The inspectors reviewed a sample of the licensees completed classifications, notifications, and PARs to verify their timeliness and accuracy. The inspectors used Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data. The specific documents reviewed are described in the attachment to this report.

These activities constituted verification of the drill/exercise performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.5 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspectors reviewed the licensees records for participation in drill and training evolutions, between October 2015 and March 2016, to verify the accuracy of the licensees data for drill participation opportunities. The inspectors verified that all members of the licensees emergency response organization (ERO) in the identified key positions had been counted in the reported performance indicator data. The inspectors reviewed the licensees basis for reporting the percentage of ERO members who participated in a drill. The inspectors reviewed drill attendance records and verified a sample of those reported as participating. The inspectors used Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data. The specific documents reviewed are described in the attachment to this report.

These activities constituted verification of the emergency response organization drill participation performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.6 Alert and Notification System Reliability (EP03)

a. Inspection Scope

The inspectors reviewed the licensees records of alert and notification system tests, conducted between October 2015 and March 2016, to verify the accuracy of the licensees data for siren system testing opportunities. The inspectors reviewed procedural guidance on assessing alert and notification system opportunities and the results of periodic alert and notification system operability tests. The inspectors used Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data. The specific documents reviewed are described in the attachment to this report.

These activities constituted verification of the alert and notification system reliability 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, system health 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 identified adverse trends. The inspectors did not review any cross-cutting themes because none exist at the site.

The inspectors identified the following trend that might indicate the existence of a more significant safety issue, and reviewed the licensees response to it. The inspectors identified multiple examples associated with the organizations implementation of their process for planning, controlling, and executing work activities such that nuclear safety is the overriding priority; which includes the identification and management of risk commensurate with the work and the need for coordination with different work groups or job activities [H.5 Work Management]. These examples included:

• CR-CNS-2015-06546. NCV 05000298/2015003-03, Failure to Control Licensed Material. This finding was assigned an H.5 Work Management cross-cutting aspect. The licensee's corrective actions for this issue were to:

(1) generate a work order for removing material from the protected area (PA) requiring radiation protection (RP) support, and

(2) revise radiation worker procedure to require licensee personnel to contact RP prior to removing material from the PA.

• CR-CNS-2016-02402. NCV 05000298/2016001-02, Failure to Assess Operability of Technical Specification System Functions during Surveillance Testing. This finding was also assigned an H.5 Work Management cross-cutting aspect. The licensees corrective action was to revise the surveillance procedures to notify the shift manager when opening environmentally qualified (EQ) terminal boxes.

• CR-CNS-2016-02207. NCV 05000298/2016002-02, Failure to Follow Work Instructions for Post-Maintenance Testing of Safety-Related Ventilation Systems. This finding, documented in Section 1R19 of this Inspection Report, was also assigned an H.5 Work Management cross-cutting aspect. The licensees corrective actions for the two examples documented in the finding were focused on individual accountability; however, an additional causal evaluation was initiated as a result of this finding.

• CR-CNS-2016-00401. The inspectors identified a failure to implement fire risk management actions (RMAs) for residual heat removal (RHR) maintenance. The licensee implemented the fire RMAs and closed the condition based on actions taken.

• CR-CNS-2016-00013. The licensee identified a failure to implement fire RMAs for a FLEX service water RHR connection modification. The licensees corrective action was to provide training to the Work Control Department on the use of risk codes in the maintenance process application.

• CR-CNS-2016-00846. The licensee identified a failure to implement fire RMAs for disassembly and inspection of service water valve SW-V-107. The licensees corrective action was to revise its fire risk management procedure for this issue.

• CR-CNS-2016-02113. The inspectors identified a failure to evaluate the opening of the EQ high pressure coolant injection (HPCI) 125 Vdc starter cabinet.

Specifically, the licensee did not evaluate the impact on the containment isolation function of HPCI steam admission valve HPCI-MOV-16. Following NRC identification, the licensee assessed operability of HPCI-MOV-16 for this condition and determined that the internal components of the HPCI 125 Vdc were EQ with the cabinet open. This action was completed prior to opening the HPCI 125 Vdc starter cabinet.

• CR-CNS-2015-03709. The licensee identified a failure to authorize non-essential lubricant prior to use for service water pump B maintenance under work order (WO) 4895872. The licensees corrective action was to conduct training with the planners on the requirements of the work planning standard procedure for the use of non-essential material in essential systems.

• CR-CNS-2016-01429. The licensee identified a failure to authorize non-essential lubricant prior to use for emergency diesel generator 1 and 2 maintenance under WOs 5000070 and 5031309. The licensees corrective action was to revise the work planning standard procedure to ensure planners had the appropriate evaluation completed prior to allowing the use of non-essential material in essential systems.

• CR-CNS-2016-02838. The licensee identified that an inappropriate post-maintenance test had been assigned and performed for work associated with hydro-lazing a Division 2 drywell spray line under WO 4958742. The work should have been assigned a containment local leak rate test. This issue was corrected via performance of the correct test upon discovery.

• CR-CNS-2016-02830. The licensee initiated this condition report for six examples of error likely situations while controlling work activities to ensure appropriate controls were in place. This condition report was closed to trend.

Examples included the following condition reports:

1. CR-CNS-2016-02431. WO 5061279 scheduled work activities in work week 1618 were delayed due to conflicts in limiting condition of operation (LCO)activities.

2. CR-CNS-2016-02400. WO 4945820 Operations 0030, 0035, 0040, and 0050 could not be completed as scheduled on April 28, 2016, due to posted protected equipment.

3. CR-CNS-2016-02500. WO 5060787 required a stand-alone clearance order due to a technical specification conflict. This conflict was not identified during the work management process for the Division 1 RHR system maintenance window.

4. CR-CNS-2016-02041. During performance of Station Procedure 6.RCIC.302 an EQ terminal box was identified. However, this terminal box was not listed as an EQ terminal box in station procedures. Following identification, the required actions for opening the terminal box were taken.

5. CR-CNS-2016-02813. WO 5060772 calibrated a service water instrument and required entry to an EQ terminal box in the reactor building. Opening this terminal box impacted technical specification required equipment. This was identified by the licensee prior to authorizing the work activity and not during the planning process.

6. CR-CNS-2016-02402. (Previously discussed) NCV 05000298/2016001-02 was an example of the complicated work coordination that needed to take place for EQ terminal box testing.

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

b. Observations and Assessments The inspectors reviewed the trend identified above and produced the following observations and assessments:

• The inspectors reviewed the above examples and concluded that four categories of the work management process were impacted. These categories included:

(1) planning of WOs;

(2) coordination of WO activities and organizational resources;

(3) execution of WO activities; and

(4) verification that WO post-maintenance testing was completed satisfactorily prior to declaring safety-related equipment operable. The licensees corrective actions and evaluations for the above examples focused on the specific area of the work management process that was impacted in each case. However, the licensee did not initially recognize the existence of a trend in this area and consequently did not consider all aspects of the work management process. In response to the inspectors observations, the licensee established an interdisciplinary team of individuals to review the trend in work management. The licensee entered this trend into their corrective action program for resolution as Condition Report CR-CNS-2016-03783.

c. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report (LER) 05000298/2016001-00, De-Energized High

Pressure Coolant Injection Auxiliary Lube Oil Pump Caused by Relay Failure Results in Loss of Safety Function and Condition Prohibited by Technical Specifications

a. Inspection Scope

On April 26, 2016, a licensed operator performing a control room panel walkdown noted that the green light for the high pressure coolant injection (HPCI) auxiliary lube oil pump (ALOP) was not illuminated. A non-licensed operator went to the local 250 Vdc starter rack to investigate and found that both the green and red power indicating lights on the starter rack were extinguished. Operations personnel attempted to start the ALOP, and it failed to start. Due to the inoperability of the ALOP, the licensee declared HPCI inoperable and entered Technical Specification Limiting Condition for Operation (LCO) 3.5.1, Condition C. Condition C required verification by administrative means that the reactor core isolation cooling (RCIC) system was operable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />; and restoration of the HPCI system to operable status within 14 days. Operations personnel immediately verified RCIC was operable by administrative means to meet this action.

The licensee initiated a root cause evaluation and created a complex troubleshooting team to determine the cause of the condition. Investigation revealed that an electrical relay for the ALOP that had been installed during a maintenance window 6 days earlier had failed due to infant mortality. Specifically, the relay coil internal to the relay had failed after approximately 133 hours0.00154 days <br />0.0369 hours <br />2.199074e-4 weeks <br />5.06065e-5 months <br /> of service. The failure was attributed to the overheating of the coil windings, caused by a manufacturing defect. The licensees root cause evaluation found that the commercial grade dedication process used by the vendor of the relay did not have sufficient checks to identify the infant mortality failure of the relay. Corrective actions included replacement of the relay and improvements within the vendors dedication process.

Because HPCI was a single train system, the licensee reported this failure under 10 CFR 50.72 and 50.73 as a condition that could have prevented the fulfillment of the safety function of a structure, system, or component (SSC) needed to mitigate the consequences of an accident. In addition, the event was reported under 50.73 as a condition prohibited by technical specifications because, due to the HPCI inoperability, verification of the RCIC system inoperability exceeded LCO action requirements prior to the licensees discovery of the defective component.

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

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Report (LER) 05000298/2016002-00, De-Energized High

Pressure Coolant Injection Auxiliary Lube Oil Pump Caused by Light Bulb Failure Results in Loss of Safety Function

a. Inspection Scope

On April 26, 2016, operations personnel in the control room noted that the green light for the high pressure coolant injection (HPCI) auxiliary lube oil pump (ALOP) was not illuminated. The HPCI system had been restored to operable status only a few hours earlier following replacement of a failed relay. A non-licensed operator went to the local 250 Vdc starter rack to investigate, and found that both the green and red power indicating lights on the starter rack were extinguished. However, in this case, the green bulb was found to be shattered and charred. Operations personnel attempted to start the ALOP, and it failed to start. Due to the inoperability of the ALOP, the licensee declared HPCI inoperable and entered Technical Specification LCO 3.5.1, Condition C.

The licensee initiated a root cause evaluation and created a complex troubleshooting team to determine the cause of the event. Investigation revealed that the light bulb installed in the green lamp socket had failed and introduced a short into the HPCI ALOP 125 Vdc control power circuit. As a result, a blown fuse caused the loss of power to the ALOP control power circuit. The failed bulb had been replaced a few hours earlier, during HPCI restoration from maintenance. The licensees root cause evaluation found that a lack of engineering knowledge with regard to the bulb shorting failure mechanism led to a 1984 design change that reduced the robustness of the circuit. Corrective actions included replacement of the bulb and socket, and implementation of training for engineering personnel with respect to this failure mechanism.

Because HPCI was a single train system, the licensee reported this failure under 10 CFR 50.72 and 50.73 as a condition that could have prevented the fulfillment of the safety function of an SSC needed to mitigate the consequences of an accident.

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

b. Findings

Introduction.

The inspectors reviewed a self-revealed, Green, non-cited violation (NCV)of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the adequacy of design of the HPCI auxiliary lube oil pump (ALOP) 125 Vdc starter circuit. Specifically, in 1984, the licensee modified the design of the starter circuit and eliminated a resistor that served to protect the circuit from shorting due to indication light bulb failures.

Description.

On April 26, 2016, at approximately 5:36 p.m., operations personnel in the control room observed that the green light indication on the control room panel for the HPCI ALOP was not illuminated. A non-licensed operator was dispatched to check the local 250 Vdc starter rack and found that the power indicating lights on the starter rack were also extinguished. The individual also observed that the local green light bulb was charred and shattered. Operations personnel attempted to start the HPCI ALOP, and the pump failed to start. After determining the HPCI ALOP had lost its control power, the licensee declared HPCI inoperable and unavailable.

The licensee initiated a root cause evaluation and determined that the green light indicating bulb had shorted in its socket, which resulted in a blown fuse in the 125 Vdc HPCI ALOP circuit. As a direct result, the circuit was deenergized, rendering the loss of power to the HPCI ALOP. The light bulb had been replaced approximately 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> earlier that day following replacement of a failed relay.

The licensees root cause evaluation discovered that the original design of the HPCI ALOP starter rack circuit had included a local indication light dropping resistor. The dropping resistor served to help prevent the loss of ALOP control power due to bulb-related shorts, by limiting the current on the indication bulb side of the circuit. However, in 1984, the circuit was modified, and a direct voltage light and socket were substituted for the dropping resistor and light combination, thereby removing the dropping resistor protection from the circuit. The licensee determined that a lack of engineering knowledge led to this design change which made the circuit vulnerable to a bulb-related short, and ultimately rendered HPCI inoperable. A contributing cause was associated with the licensees use of nonessential bulbs in the essential HPCI circuit which further increased vulnerability to this failure mechanism. The inspectors determined that this issue was self-revealed because it was identified as a result of a condition that became apparent through a readily detectable degradation in material condition, capability, or functionality of equipment or plant operations; and constituted an obvious equipment failure.

Analysis.

The licensees failure to verify the adequacy of design of the HPCI ALOP starter circuit in accordance with 10 CFR Part 50, Appendix B, Criterion III, Design Control, was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment performance 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. Specifically, at the time the modification was installed, the licensee had not taken sufficient actions to ensure that the electrical circuit was protected from light bulb shorting failures, resulting in HPCI being rendered inoperable. Using Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, the inspectors were directed to Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. Using Appendix A, the inspectors assumed that the finding represented a loss of system and function of high pressure coolant injection and determined the finding required a detailed risk evaluation. A senior reactor analyst performed a detailed risk evaluation assuming high pressure coolant injection would have failed to start. The exposure time was estimated by applying a t/2 exposure period methodology to the approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> since the circuit was last known to be working and obtained 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of exposure time. The analyst then added in the 19 hour2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> repair time to yield a 21 hour2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> total exposure period. These assumptions yielded an increase in core damage frequency of 5.2E-8/year and the finding was therefore of very low safety significance (Green). The estimate was attained using the Cooper Nuclear Station SPAR Model, Revision 8.22, run on SAPHIRE, Version 8.1.4. Transients, losses of service water, and losses of condenser heat sink were the dominant core damage sequences. The reactor core isolation cooling system and the ability to depressurize with safety relief valves were the major remaining equipment which mitigated the increase in core damage frequency. A cross-cutting aspect was not assigned to this finding because the performance deficiency occurred in 1984, and therefore, is not indicative of current licensee performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that for those systems, structures, and components to which this appendix applies, Design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.

Contrary to the above, since 1984, for quality-related components associated with the HPCI ALOP starter circuit, to which 10 CFR Part 50, Appendix B, applies, the licensee failed to ensure that design control measures provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Specifically, in 1984, the licensee modified the design of the starter circuit and eliminated a resistor that served to protect the circuit from shorting due to indication light bulb failures. Immediate corrective actions included replacing the light socket and blown fuse, and changing out the nonessential light bulb with an essential bulb. Because this violation was of very low safety significance (Green) and was entered into the licensees corrective action program as Condition Report CR-CNS-2016-02318, this violation is being treated as a non-cited violation (NCV) in accordance with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000298/2016002-03, Failure to Maintain Design Control for High Pressure Coolant Injection System Electrical Circuit)

4OA5 Other Activities

Follow Up Inspection for Three or More Severity Level IV Traditional Enforcement Violations in the Same Area in a 12-Month Period

a. Inspection Scope

The inspectors performed Inspection Procedure (IP) 92723, Follow Up Inspection for Three or More Severity Level IV Traditional Enforcement Violations in the Same Area in a 12-Month Period, based on the results of the NRCs annual review of station performance as documented in the 2015 assessment letter dated March 2, 2016 (ML16061A312). In 2015, the NRC issued the following three Severity Level (SL) IV traditional enforcement violations in the area of impeding the regulatory process:

• NCV 05000298/2015004-02, Failure to Update the Updated Safety Analysis Report

• NCV 05000298/2015007-03, Failure to Update the Final Safety Analysis Report (FSAR)

• NCV 05000298/2015003-04, Failure to Make a 10 CFR 50.72(b)(2)(xi)

Notification The inspectors reviewed the licensees cause evaluation and corrective actions associated with these issues in order to determine whether the licensees actions met the IP 92723 inspection objectives to provide assurance that:

(1) the cause(s) of the violations are understood by the licensee,

(2) the extent of condition and extent of cause of the violations are identified, and

(3) licensee corrective actions to the violations are sufficient to address the cause(s).

b. Findings and Observations

No findings were identified.

The inspectors determined that the licensees actions to identify the causes of the violations were adequate to meet objective

(1) above, and that the licensees corrective actions were adequate to meet objective (3). The inspectors developed the following observations with regard to the licensees actions to meet objective

(2) regarding identification of extent of condition and extent of cause.

The inspectors noted that the NCVs referenced above included five examples of failures to update the updated safety analysis report (USAR) in accordance with the requirements of 10 CFR 50.71(e). Three of these examples involved new or updated information that was included in license amendments, while two examples involved new information that was introduced in licensee procedure changes. The inspectors determined that the licensees extent of condition evaluation included a review of a sample of license amendments to determine whether additional examples of failures to make appropriate corresponding updates to the USAR existed. The inspectors observed that the evaluation did not include a sample of output of any other change processes by which new or updated information affecting the content of the USAR could be developed, such as licensee procedure changes.

The inspectors also observed that, for the identified cause of failure to apply the proper rigor for regulatory requirements associated with USAR maintenance, the licensees extent of cause evaluation did not assess the applicability of the cause for other programs or activities, such as whether proper rigor is being applied for maintaining licensee-controlled licensing basis documents other than the USAR.

Based on these observations, the inspectors concluded that objective

(2) above was not met, in that the licensee did not fully identify the extent of condition and extent of cause of multiple SL IV traditional enforcement violations. The licensee entered these observations into the corrective action program as Condition Reports CR-CNS-2016-03780 and CR-CNS-2016-03708 for further evaluation.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On May 3, 2016, the inspectors conducted a telephonic discussion of the preliminary exercise scenario for the June 14, 2016, exercise, submitted April 14, 2016, with Mr. J. Stough, Manager, Emergency Preparedness, and other members of the licensee staff. The licensee acknowledged the issues presented.

On June 23, 2016, the inspectors conducted a telephonic exit meeting to present the results of the inspection of the licensees biennial emergency plan exercise conducted June 14, 2016, to Mr. K. Higginbotham, General Manager, Plant Operations, and other members of the licensee staff. The licensee acknowledged the issues presented.

On June 23, 2016, the inspector obtained the final annual requalification training program cycle results and exited with Mr. E. Jackson, Exam Writer. The inspector did not review any proprietary information during this inspection.

On June 30, 2016, the inspectors presented the results of the IP 92723 inspection to Mr. O.

Limpias, Vice President and Chief Nuclear Officer, and other members of the licensee staff. The licensee acknowledged the issues presented.

On July 13, 2016, the inspectors presented the inspection results to Mr. O. Limpias, Vice President and Chief Nuclear Officer, 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

M. Bacon, Manager, Training

K. Bantz, Manager, Work Control

T. Barker, Manager, Engineering Program and Components

K. Billesback, Manager, Material, Purchasing and Contracts

D. Buman, Director, Engineering

W. Chapin, Manager, Maintenance

T. Chard, Manager, Quality Assurance

L. Dewhirst, Manager, Corrective Action and Assessment

K. Dia, Manager, System Engineering

R. Estrada, Design Engineering Manager

J. Flaherty, Senior Licensing Engineer

J. Florence, Supervisor, Simulator

D. Goodman, Manager, Operations

B. Hasselbring, Assistant Manager, Operations, Shift

K. Higginbotham, General Manager, Plant Operations

E. Jackson, Exam Writer

J. Kahanca, Assistant Manager, Operations, Training

D. Kimball, Director, Nuclear Oversight

O. Limpias, Vice President, Chief Nuclear Officer

R. Penfield, Director, Nuclear Safety Assurance

J. Shaw, Manager, Licensing

J. Stough, Manager, Emergency Preparedness

C. Sunderman, Manager, Radiation Protection

M. Tackett, Manager, Outage

D. VanDerCamp, Senior Licensing Engineer

C. Walgren, Site Manager, Procurement

NRC Personnel

C. Gregg, Branch Chief, Technological Hazards Branch, FEMA Region VII

N. Valentine, Senior Site Specialist, FEMA Region VII

C. Christianson-Riley, Site Specialist, FEMA Region VII

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Failure to Meet Technical Specification Requirements for

05000298/2016002-01 NCV Traversing In-Core Probe B Ball Valve (Section 1R12)

Failure to Follow Work Instructions for Post-Maintenance Testing

05000298/2016002-02 NCV of Safety-Related Ventilation Systems (Section 1R19)

Failure to Maintain Design Control for High Pressure Coolant

05000298/2016002-03 NCV Injection System Electrical Circuit (Section 4OA3)

Attachment

Closed

De-Energized High Pressure Coolant Injection Auxiliary Lube Oil Pump Caused by Relay Failure Results in Loss of Safety

05000298/2016001-00 LER Function and Condition Prohibited by Technical Specifications (Section 4OA3)

De-Energized High Pressure Coolant Injection Auxiliary Lube

05000298/2016002-00 LER Oil Pump Caused by Light Bulb Failure Results in Loss of Safety Function (Section 4OA3)