IR 05000298/2014003

IR 05000298-14-003; 04/01/2014 - 06/30/2014; Cooper Nuclear Station; Integrated Resident & Regional Report; Equipment Alignment, Maintenance Effectiveness, Operability Determination and Functionality Assessment

ML14225A856
Person / Time
Site:	Cooper
Issue date:	08/12/2014
From:	Allen D NRC/RGN-IV/DRP/RPB-C
To:	Limpias O Nebraska Public Power District (NPPD)
Allen D
References
IR-2014-003
Download: ML14225A856 (50)

Text

UNITED STATES ust 12, 2014

SUBJECT:

COOPER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000298/2014003

Dear Mr. Limpias:

On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Cooper Nuclear Station. On June 23, 2014, 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 two findings of very low safety significance (Green) in this report.

Both of these findings involved violations of NRC requirements. Additionally, NRC inspectors documented one Severity Level IV violation with no associated finding. 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 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, 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 or a finding not associated with a regulatory requirement, 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 NRCs 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/

Donald B. Allen, Chief Project Branch C Division of Reactor Projects Docket Nos.: 50-298 License Nos.: DPR-46

Enclosure:

Inspection Report 05000298/2014003 w/Attachments:

1. Supplemental Information 2. Request for Information for the TI 2515-182 Phase 2 Inspection 3. Request for Information for the O

REGION IV==

Docket: 05000298 License: DPR-46 Report: 05000298/2014003 Licensee: Nebraska Public Power District Facility: Cooper Nuclear Station Location: 72676 648 A Ave Brownville, NE Dates: April 1 through June 30, 2014 Inspectors: J. Josey, Senior Resident Inspector C. Henderson, Resident Inspector C. Alldredge, Health Physicist P. Hernandez, Health Physicist J. Drake, Senior Reactor Inspector P. Elkmann, Senior Emergency Preparedness Inspector M. Keefe, Human Factors Specialist C. Norton, Project Manager Approved Donald B. Allen, Chief By: Project Branch C Division of Reactor Projects Enclosure

SUMMARY

IR 05000298/2014003; 04/01/2014 - 06/30/2014; Cooper Nuclear Station; Integrated Resident

& Regional Report; Equipment Alignment, Maintenance Effectiveness, Operability Determination and Functionality Assessment The inspection activities described in this report were performed between April 1 and June 30, 2014, by the resident inspectors at the Cooper Nuclear Station and six inspectors from the NRCs Region IV office and other NRC offices. Two findings of very low safety significance (Green) are documented in this report. Both of these findings involved violations of NRC requirements. Additionally, NRC inspectors documented in this report one Severity Level IV violation with no associated finding. 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 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.

Inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, associated with the licensees failure to assure that the applicable design basis for applicable structures, systems, and components were correctly translated into specifications, procedures, and instructions. Specifically, the licensee failed to correctly translate design requirements associated with high energy line breaks into the as-built facility for the service water pump room, diesel generator rooms 1 and 2, cable spreading room, and 4160 Vac vital switch gear room G. This does not represent an immediate safety concern because the licensee performed operability assessments for the affected areas, which established a reasonable expectation for operability pending resolution of the identified issue. The licensee entered this deficiency into their corrective action program for resolution as Condition Report CR-CNS-2014-01828.

The failure to ensure that design requirements were correctly translated into installed plant equipment was a performance deficiency. This 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 affected the associated objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to translate the design requirements into installed plant equipment resulted in a condition where structures, systems and components necessary to mitigate the effects of a high energy pipe break may not have functioned as required. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, inspectors determined that the finding was of very low safety significance (Green) because the finding: (1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of at least a single train for longer than its allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significance in accordance with the licensees maintenance rule program.

Inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor of this finding occurred in 2003, and does not reflect current licensee performance. (Section 1R04)

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, associated with the licensees failure to follow the requirements of Station Procedure 0.41, Seismic Housekeeping, Revision 10.

Specifically, the licensee stored a rolling scaffold in the vicinity of Division II service water booster pumps and failed to properly restrain it. The licensee restrained the rolling scaffold in accordance with Station Procedure 0.41 and assessed operability of the service water booster pumps. The licensee determined that during the time the rolling scaffold was unrestrained one of the Division II service water booster pumps was inoperable. The licensee entered this deficiency into their corrective action program for resolution as Condition Report CR-CNS-2014-03000.

The licensees failure to follow Station Procedure 0.41 seismic housekeeping requirements for a rolling scaffold in the vicinity of Division II service water booster pumps was a performance deficiency. This 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 affected the associated objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the unrestrained scaffolding resulted in a condition where during a seismic event a service water booster pump may not have been able to perform its specified safety function. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, inspectors determined that the finding was of very low safety significance (Green) because the finding: (1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of a least a single train for longer than its technical specification allowed outage time; and (4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significance in accordance with the licensees maintenance rule program. The finding has a cross-cutting aspect in the area of human performance associated with training because the organization failed to provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values [H.9]. (Section 1R15)

OTHER FINDINGS AND VIOLATIONS Severity Level IV. Inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.73, Licensee Event Report, associated with the licensees failure to submit a licensee event report within 60 days following discovery of an event meeting the reportability criteria. Specifically, a condition prohibited by technical specifications existed for trip and throttle valve RCIC-MOV-14 for a period of time longer than the allowed outage time. This does not represent an immediate safety concern because this issue is only associated with reporting requirements. The licensee entered this deficiency into their corrective action program for resolution as Condition Reports CR-CNS-2014-03387 and CR-CNS-2014-03457.

The licensees failure to submit a licensee event report within 60 days following discovery of an event meeting the reportability criteria was a performance deficiency. Because this performance deficiency had the potential to impact the NRCs ability to perform its regulatory function, inspectors evaluated the performance deficiency using traditional enforcement.

The violation was evaluated using Section 2.3.11 of the NRC Enforcement Policy, because the failure to submit a required licensee event report may impact the ability of the NRC to perform its regulatory oversight function. In accordance with Section 6.9, Example 9, of the NRC Enforcement Policy, this violation was determined to be a Severity Level IV non-cited violation. Inspectors determined that a cross-cutting aspect was not applicable to this performance deficiency because the failure to make a required report was strictly associated with a traditional enforcement violation (Section 1R12).

PLANT STATUS

The Cooper Nuclear Station began the inspection period at full power on April 1, 2014. On May 30, 2014, the licensee shut down the plant for Planned Outage 2014-01 to replace reactor recirculation pumps A and B seals. They returned the plant to full power on June 7, 2014, where it remained for the rest of the reporting period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Summer Readiness for Offsite and Alternate AC Power Systems

a. Inspection Scope

On April 22, 2014, the inspectors completed an inspection of the stations off-site and alternate-ac power systems. The inspectors inspected the material condition of these systems, including transformers and other switchyard equipment to verify that plant features and procedures were appropriate for operation and continued availability of off-site and alternate-ac power systems. The inspectors reviewed outstanding work orders and open condition reports for these systems. The inspectors walked down the switchyard to observe the material condition of equipment providing off-site power sources.

These activities constituted one sample of summer readiness of off-site and alternate-ac power systems, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

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

• May 22, 2014, Primary containment isolation valves HPCI-MOV-15 and 16

• June 30, 2014, Residual heat removal suppression pool cooling, Division II

• June 30, 2014, Safety relief valves 1 and 7, low-low set safety/relief valves 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

Failure to Correctly Translate Design Requirements into Installed Plant Configuration

Introduction.

Inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with the licensees failure to assure that the applicable design basis for applicable structures, systems, and components were correctly translated into specifications, procedures, and instructions.

Description.

During walk downs of the service water pump room, diesel generator rooms 1 and 2, cable spreading room, and 4160 Vac vital switch gear room G, inspectors noted that auxiliary steam piping (heating steam) was located in these rooms.

Inspectors questioned whether this was high energy piping and how it had been evaluated for potential environmental effects. Subsequently, inspectors noted that this piping was the subject of previous evaluations by the licensee, Condition Reports RCR 2000-1213 (PIR4-12920) and CR-CNS-2005-04427.

Condition Report RCR 2000-1213 identified that auxiliary steam piping was in the vicinity of safety-related equipment in the service water pump room, diesel generator rooms, and the cable spreading room. This condition report documented an operability assessment to establish a reasonable expectation for operability, and went on to assign the identified issue to the high energy line break reconstitution effort that was currently in process. No other actions were taken. Condition Report CR-CNS-2005-04427 identified that auxiliary steam piping was located in the southwest corner of the G critical switchgear room. This condition report stated, in part, However, as documented in Licensing Memorandum LIC2003002, High Energy Line Break Licensing Basis, the Cooper Nuclear Station Licensing Basis does not require consideration of high energy line break critical cracks environmental effects outside the secondary containment.

This condition report was subsequently closed with no actions taken. Inspectors also noted that the stations Environmental Qualification Program Basis Document, Revision 7, Section 3.3.2.4.2.B state, in part, The Cooper Nuclear Station licensing basis precludes evaluating the effects of auxiliary steam line breaks outside the reactor building (secondary containment) as a basis for including equipment in the Environmental Qualification Program, and references Licensing Memorandum LIC2003002.

Inspectors questioned the position taken by the licensee through Licensing Memorandum LIC2003002. During reviews of the stations Updated Safety Analysis Report, Final Safety Analysis Report, Amendments 20 and 25, and the Safety Evaluation Report of Cooper Nuclear Station, Supplement Number 1, dated July 16, 1973, they noted that high energy piping systems are defined as those systems whose service temperature exceeds 200 degrees Fahrenheit or whose service pressure exceeds 275 psig, and systems that meet at least one of these two thresholds are required to be evaluated for environmental effects that could occur from a single open crack in the most adverse location of the piping system. The Updated Safety Analysis Report, Section IV-12 states, in part:

In addition, the effects of high energy pipe breaks were evaluated on the following systems, components, and structures which would be necessary (in various combinations, depending on the effects of the break) to safely shut down, cool down, and maintain cold shutdown conditions of the plant:

A. General 1. Control Room 2. Control and Instrument Cables 3. Electrical Distribution Systems 4. Emergency DC Power Supply (batteries)5. Emergency AC Power Supply (diesels)6. Heating and Ventilation Systems D. Service Systems 1. Service Water System Based on the above information, and consultation with the Office of Nuclear Reactor Regulation, it was determined that the evaluation of auxiliary steam piping outside the secondary containment was part of the stations licensing and design basis. Therefore, inspectors determined that the licensee had failed to correctly translate applicable design requirements into the as-built facility. Inspectors informed the licensee of their concern, and the licensee initiated Condition Reports CR-CNS-2013-07073 and CR-CNS-2013-07142. This does not represent an immediate safety concern because the licensee performed operability assessments for the affected areas which established a reasonable expectation for operability pending resolution of the identified issue.

Analysis.

The failure to ensure that design requirements were correctly translated into installed plant equipment was a performance deficiency. This 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 affected the associated objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to translate the design requirements into installed plant equipment resulted in a condition where structures, systems and components necessary to mitigate the effects of a high energy pipe break may not have functioned as required. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, inspectors determined that the finding was of very low safety significance (Green) because the finding:

(1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality;

(2) did not represent a loss of system and/or function;

(3) did not represent an actual loss of function of at least a single train for longer than its allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and

(4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significance in accordance with the licensees maintenance rule program.

Inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor of this finding occurred in 2003, and does not reflect current licensee performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, that, measures shall be established to assure that applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the license application, for those components to which this appendix applies, are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, measures established by the licensee did not assure that applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the license application, for those components to which this appendix applies, were correctly translated into specifications, drawings, procedures, and instructions. Specifically, from initial construction to present, the licensee failed to fully incorporate applicable design requirements for components needed to ensure the capability to shut down the reactor and maintain it in a safe shutdown condition following a high energy line break. This violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy. The violation was entered into the licensees corrective action program as Condition Report CR-CNS-2014-01828. (NCV 05000298/2014003-01, Failure to Correctly Translate Design Requirements into Installed Plant Configuration)

.2 Complete Walkdown

a. Inspection Scope

On April 24, 2014, the inspectors performed a complete system walkdown inspection of the reactor core isolation cooling system. The inspectors reviewed the licensees procedures and system design information to determine the correct reactor core isolation cooling lineup for the existing plant configuration. The inspectors also reviewed outstanding work orders, open condition reports, in-process design changes, temporary modifications, and other open items tracked by the licensees operations and engineering departments. The inspectors then visually verified that the system was correctly aligned for the existing plant configuration.

These activities constituted one complete system walkdown sample, 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 23, 2014, Reactor equipment cooling heat exchanger and pump area, Fire Area I, Zone 3C

• May 28, 2014, Auxiliary relay room, Fire Area VII, Zone 8A

• June 19, 2014, Fire impairment FP-BLDG-Door-R208, Fire Area II, Zone 3A

• June 19, 2014, Reactor building elevation 958 feet, reactor building elevator and access way area, Fire Area I, Zone 4A 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 June 18, 2014, the inspectors observed a portion of an annual requalification test for licensed operators, and an evaluated simulator scenario performed by an operating crew, and simulator training for an operating crew. The inspectors assessed the performance of the operators and the evaluators critique of their performance.

These activities constitute 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 May 30, 2014, 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 due to reactor shutdown and placing residual heat removal into service.

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

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

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• June 19, 2014, Reactor core isolation cooling, trip and throttle valve RCIC-MOV-14 pin out of position and steam supply valve RCIC-MOV-131 failed to close The inspectors reviewed the extent of condition of possible common cause structure, system, and component 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 structure, system, and component. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.

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

b. Findings

Introduction.

Inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.73, Licensee Event Report, associated with the licensees failure to submit a licensee event report within 60 days following discovery of an event meeting the reportability criteria.

Description.

On February 25, 2014, during the reactor core isolation cooling limited condition of operation maintenance window the licensee discovered the linkage pin for the reactor core isolation cooling trip and throttle valve RCIC-MOV-14 was out of position about 1/2 inch. The licensee initiated Condition Report CR-CNS-2014-01026 to capture this issue in the stations corrective action program.

Condition Report CR-CNS-2014-01026 documented the past operability and reportability evaluation for RCIC-MOV-14. This condition report was classified as a work item to correct the condition with specific work instruction for the installation of the RCIC-MOV-14 linkage pin and set screws. The past operability and reportability evaluation stated, in part:

The pin, as-found, would have not prohibited reactor core isolation cooling from performing its technical specification function. The as-found condition on February 25, 2014 had the pin in the proper position to assist in the performance of the trip reset after a reactor level high level (level 8) trip. The valve would have reset if allowed to do so. The question only related to operation going forward. Based on the condition description and information from system engineering, there is no traceability of the condition to a specific point in time.

Thus, time of condition is time of discovery. Therefore, this is also not a condition prohibited by technical specification.

Inspectors questioned the past operability determination. Specifically, inspectors noted that; the as-found condition of the linkage pin and set screws for trip and throttle valve RCIC-MOV-14 would not meet the systems seismic design requirements for the system, and this condition appeared to represent an instance where a condition had existed for a time longer than permitted by the stations technical specifications, and was reportable.

During follow up discussions with engineering personnel on February 27, 2014, inspectors were informed that the issue with the pin was a result of an inadequate maintenance procedure that had been implemented in 2010.

Based on this discussion inspectors determined that the licensee had identified the cause of the condition, and the time condition was introduced (2010), and it represented a reportable condition. Therefore, February 27, 2014, was determined to be the date of discovery. Inspectors informed the licensee of their concerns and the licensee initiated Condition Report CR-CNS-2014-01072.

As of April 28, 2014, the licensee had not submitted a Licensee Event Report for this issue. Inspectors determined that the licensee had missed a required 60 day report.

Follow up discussions with the licensee revealed that the licensee had failed to adequately evaluate past operability. Specifically, the seismic design requirements of the system had not been considered during their evaluation. The licensee initiated Condition Report CR-CNS-2014-03387 on June 3, 2014, to capture this issue in the stations corrective action program, and the licensee subsequently determined that RCIC-MOV-14 had been inoperable for greater than the allowed technical specification outage time for reactor core isolation cooling system and was reportable.

Enforcement.

Title 10 CFR 50.73(a)(1) requires, in part, that the licensee shall submit a licensee event report for any event of the type described in this paragraph within 60 days after the discovery of the event. Title 10 CFR 50.73(a)(2)(i)(B) requires, in part, that the licensee report any operation or condition prohibited by the plants technical specification. Contrary to the above, the licensee failed to submit a licensee event report for an event of the type described in this paragraph within 60 days after the discovery of the event. Specifically, from April 28, 2014, until June 27, 2014, the licensee failed to make a required report within 60 days after the discovery a condition prohibited by technical specifications. Because this violation has been entered into the corrective action program as Condition Report CR-CNS-2014-03387, compliance was restored in a reasonable amount of time, and the violation was not repetitive or willful, this Severity Level IV violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy. (NCV 05000298/2014003-02, Failure to Report Conditions Prohibited by Technical Specifications)

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed four 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 24, 2014, Diesel generator 1 limiting condition for operation maintenance window risk management actions for high pressure coolant injection

• April 29, 2014, Dry storage fuel campaign material storage on elevation 903 feet of the reactor building

• May 19, 2014, RCIC-MOV-15 and SW-MOV-89B maintained available during Appendix R modification on MCC-Y Local Alternate Shutdown Panel

• June 30, 2014, Planned outage 2014-01 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.

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

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

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

• April 29, 2014, Operability determination of the diesel generator 1 turbocharger lube oil filter snap ring incorrectly

• May 21, 2014, Operability determination of unrestrained scaffolding near service water booster pump D

• June 30, 2014, Operability determination of the connection overstress on hanger EE-SBSWG for the 4160 V, bus 1F

• June 30, 2014, Operability determination of the high pressure coolant injection system roof plug

• June 30, 2014, Operability determination of average drywell temperature of 135 F instead of tech spec limit of 150 F for design basis loss-of-coolant accidents The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded structure, system, or component 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 structure, system, or component.

These activities constitute completion of five operability review samples, as defined in Inspection Procedure 71111.15.

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with the licensees failure to follow the requirements of Station Procedure 0.41, Seismic Housekeeping, Revision 10, for a rolling scaffold in the vicinity of Division II service water booster pumps.

Description.

On May 19, 2014, while performing a plant-status walkdown in the control building basement, the inspectors identified a rolling scaffold in the vicinity of the Division II service water booster pumps which was not restrained in accordance with Station Procedure 0.41, Seismic Housekeeping, Revision 10. Inspectors identified this issue to maintenance personnel in the immediate area, and they re-stowed and restrained the rolling scaffold in accordance with Station Procedure 0.41 and initiated Condition Report CR-2014-03000 to capture this concern in the stations corrective action program.

The licensee documented an operability assessment, which determined that due to the arrangement of the Division II service water booster pumps and the size of the scaffolding that there was a potential to cause significant damage. Specifically, the impact from the scaffold tipping over could have failed the gland water line for one of the Division II service water booster pumps. Therefore, during the time the rolling scaffolding was unrestrained one of the Division II service water booster pumps was inoperable requiring entry into Technical Specification Limited Condition of Operation 3.7.1.

The licensees evaluation concluded that the cause of this issue was that maintenance personnel had inappropriately classified the rolling scaffolding as a tended item, instead of a temporary item, and in accordance with Station Procedure 0.41 the rolling scaffolding should have been restrained or met the required seismic safe standoff distance from safety-related equipment.

Analysis.

The licensees failure to follow Station Procedure 0.41 seismic housekeeping requirements for a rolling scaffold in the vicinity of Division II service water booster pumps was a performance deficiency. This 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 affected the associated objectives. Specifically, the unrestrained scaffolding resulted in a service water booster pump to be inoperable. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, inspectors determined that the finding was of very low safety significance (Green) because the finding:

(1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality;

(2) did not represent a loss of system and/or function;

(3) did not represent an actual loss of function of a least a single train for longer than its technical specification allowed outage time; and

(4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significance in accordance with the licensees maintenance rule program. The finding has a cross-cutting aspect in the area of human performance associated with training because the organization failed to provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values [H.9].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, "title" requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, and drawings. Contrary to the above, activities affecting quality that were prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances were not accomplished in accordance with these instructions, procedures, and drawings. Specifically, on May 19, 2014, the licensee failed to follow the seismic housekeeping requirements for a rolling scaffold specified in Station Procedure 0.41, Seismic Housekeeping, Revision 10. The licensee corrected this issue by re-stowing and restraining the rolling scaffold in accordance with Station Procedure 0.41. This violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy. The violation was entered into the licensees corrective action program as Condition Report CR-CNS-2014-03000. (NCV 05000298/2014003-03, Failure to Follow Seismic Housekeeping Requirements for Scaffolding)

1R19 Post-Maintenance Testing

a. Inspection Scope

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

• May 9, 2014, Service water pump C

• May 21, 2014, Control room emergency filtration system limiting condition for operation maintenance window

• June 23, 2014, Standby gas treatment B maintenance

• June 23, 2014, Service water booster pump B replacement The inspectors reviewed licensing and design-basis documents for the structures, systems, and components, 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 structures, systems, and components.

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

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

During the stations outage that concluded on June 7, 2014, the inspectors evaluated the licensees outage activities. The inspectors verified that the licensee considered risk in developing and implementing the outage plan, appropriately managed personnel fatigue, and developed mitigation strategies for losses of key safety functions. This verification included the following:

• Review of the licensees outage plan prior to the outage

• Monitoring of shut-down and cool-down activities

• Verification that the licensee maintained defense-in-depth during outage activities

• Monitoring of heat-up and startup activities These activities constitute completion of one outage activities sample, as defined in Inspection Procedure 71111.20.

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:

In-service tests:

• June 3, 2014, RHR-MOV-17 and 18 Reactor coolant system leak detection tests:

• April 30, 2014, reactor coolant system leakage determination Other surveillance tests:

• June 30, 2014, Division I low-low set permissive channel calibration and logic tests 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 structures, systems, and components following testing.

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

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspector performed an in-office review of:

• Procedure EPIP 5.7.6, Notification, Revision 59;

• Procedure EPIP 5.7.1, Emergency Classification, Revision 50 These revisions:

• Added information to the emergency notification form;

• Added directions to clarify information entered on the emergency notification form;

• Added halon gas to the list of chemicals that may cause an immediately dangerous to life and health atmosphere in emergency action levels HU3.1, Toxic, corrosive, asphyxiant, or flammable gases in amounts that have or could affect normal plant operations, and HA3.1, Access to any Table H-1 area is prohibited because of toxic, corrosive, asphyxiant, or flammable gases which jeopardize operation of systems required to maintain safe operations, or safely shutdown the reactor.

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 Document 99-01, Emergency Action Level Methodology, Revision 5, and to the standards in 10 CFR 50.47(b) to determine if the revision adequately implemented the requirements of 10 CFR 50.54(q)(3) and 50.54(q)(4).

The inspector verified that the revisions did not reduce 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 constitute completion of two emergency action level and emergency plan change samples as defined in Inspection Procedure 71114.04.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

The inspectors assessed licensee performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). During the inspection, the inspectors interviewed licensee personnel and reviewed licensee performance in the following areas:

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

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

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

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

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

• Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection These activities constitute completion of one sample of occupational ALARA planning and controls as defined in Inspection Procedure 71124.02.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

The inspectors evaluated the accuracy and operability of the licensees personnel monitoring equipment, verified the accuracy and effectiveness of the licensees methods for determining total effective dose equivalent, and verified that the licensee was appropriately monitoring occupational dose. The inspectors interviewed licensee personnel, walked down various portions of the plant, and reviewed licensee performance in the following areas:

• External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters

• The technical competency and adequacy of the licensees internal dosimetry program

• Adequacy of the dosimetry program for special dosimetry situations such as declared pregnant workers, multiple dosimetry placement, and neutron dose assessment

• Audits, self-assessments, and corrective action documents related to dose assessment since the last inspection These activities constitute completion of one sample of occupational dose assessment as defined in Inspection Procedure 71124.04.

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 June 23, 2013, through June 30, 2014, 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 June 23, 2013 through June 30, 2014 to verify the accuracy and completeness of the reported data. The inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample on June 19, 2014. 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 Identified Leakage (BI02)

a. Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system identified leakage for the period of June 23, 2013, through June 30, 2014 to verify the accuracy and completeness of the reported data. The inspectors observed the performance of the reactor coolant system leakage surveillance procedure on April 30, 2014. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

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

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

a. Inspection Scope

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

b. Findings

No findings were identified.

.2 Semiannual Trend Review

a. Inspection Scope

The inspectors reviewed the licensees corrective action program, performance indicators, 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 also reviewed the licensees progress in addressing an existing cross-cutting theme in the areas of conservative bias H.14 and procedure adherence H.8.

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

b. Findings

No findings were identified.

Cross-Cutting Issues Trend Review

(1) Cross-Cutting Theme in Conservative Bias H.14 [Previously Conservative Decision Making H.1(b)

In the 2012 mid-cycle assessment letter, dated September 4, 2012, the NRC opened a substantive cross-cutting issue in the decision making component of the human performance area involving the use of conservative decision making H.1(b). The NRC determined that a substantive cross-cutting issue existed because:

(1) there was a concern with the licensees scope of effort and progress in addressing this cross-cutting theme, and

(2) this theme repeated a theme that had previously been identified in the 2009 mid-cycle and end-of-cycle assessment letters, declared a substantive cross-cutting issue in the 2010 end-of-cycle letter, reviewed in the 2011 mid-cycle letter, and closed in the 2011 end-of-cycle letter. The assessment letter stated that the substantive cross-cutting issue would remain open until your staff demonstrated sustainable performance improvements as evidenced by effective implementation of an appropriate corrective action plan that resulted in no safety significant inspection finding and a notable reduction in the overall number of inspection findings with the same common theme.

Actions taken by the licensee to correct this issue included initiating CR- 2013-01740, 2012 NRC Annual Assessment Letter Identified 3 Substantive Cross-Cutting Issues, on March 4, 2013. The licensees investigation determined that the root causes for the substantive cross-cutting issue were:

• The stations standards related to the resolution of apparently low significance regulatory issues were low and did not meet Entergy fleet or industry expectations.

This was evidenced by a lack of urgency to fully understand and resolve substantive cross-cutting issues and NRC findings of low significance (Green).

• The stations Engineering and Operations departments were not adequately proficient in the application of the licensing and design basis of the plant. Weak design basis knowledge together with limited experience related to the application of the design basis, particularly in engineering, resulted in the reduced levels of proficiency.

The licensees corrective actions for the identified causes were:

• Assign mentors to review key engineering analysis products,

• Revise the stations corrective action program for how violations and substantive cross-cutting issues were evaluated,

• Conduct operability training with the operations department, and

• Conduct training on the stations design and licensing basis with engineering and operations departments.

On October 8, 2013, the NRC was notified of the licensees readiness for inspection of this substantive cross-cutting issue. The NRCs review of the stations progress is documented in Inspection Report 05000298/2013005. The NRC identified no safety significant inspection findings and a notable reduction in the overall number of inspection findings with the same common theme. This substantive cross-cutting issue was closed in the end-of-cycle assessment letter dated March 4, 2014. However, it was identified that the NRC would continue to review the effectiveness of the stations corrective actions because this area continued to constitute a cross-cutting theme.

This baseline inspection semi-annual trend review monitored for continued sustainable performance improvements as evidenced by effective implementation of an appropriate corrective action plan that results in no safety significant inspection findings and a notable reduction in the overall number of inspection findings with the same common theme.

To date the NRC has identified four findings with the cross-cutting aspect of H.1(b)/H.14] in the past 4 quarters (current assessment period) and this continues to comprise a cross-cutting theme. Inspectors noted that the licensee has not re-evaluated the effectiveness of their corrective actions with regard to the number of identified findings with the same common theme. Inspectors will continue to monitor for sustained improvement.

(2) Cross-Cutting Theme in Procedure Adherence H.8 [Previously Procedural Compliance H.4(b)

The licensee noted that the station had four findings with a cross-cutting aspect of H.4(b)and initiated Condition Report CR-2014-00924, NRC Findings With CCA of H.4(b), on March 25, 2014. The licensees investigation, which was completed on April 8, 2014, identified the following as the root and contributing causes:

• The site has not adequately established or reinforced an expectation for Managing Defenses in the station Human Performance strategy.

• The CNS workforce includes a high number of workers with low levels of experience, proficiency, and qualification.

The licensees corrective actions for the identified cause were:

• Develop human performance fundamentals training, for managers and supervisors for select departments.

• Revise the training programs for the select departments to require this training material be presented on a specified frequency for retraining.

To date the NRC has identified five findings with the cross-cutting aspect of H.4(b)/H.8],

and this constitutes a cross-cutting theme. Inspectors noted that the licensee is still in the process of implementing the identified corrective actions to address their identified causes.

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

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

.1 (Closed) Licensee Event Report (LER) 05000298/2014-002-00, Jacket Water Leak into

Emergency Diesel Generator Engine Results in Condition Prohibited by Technical Specifications and Loss of Safety Function

a. Inspection Scope

On October 7, 2013, emergency diesel generator 1 was declared inoperable for the performance of the monthly operability test. During this test, indications of water intrusion into the diesels lubricating oil system were observed. The licensee determined that a crack in the liner wall was visible near the top of the 1-left cylinder liner. The liner was removed and a new liner was installed. The diesel was declared operable on October 12, 2013.

The removed liner was sent to a vendor for metallurgical examination. The examination results, provided to the licensee in February 2014, found that the tensile strength of the liner in the area of crack was 15 percent lower than specifications. A slight increase in assembly stress imposed by the installation of the new cylinder in October 2011 caused a fatigue crack to initiate in the liner with lower than expected tensile strength. The crack propagated through the liner wall and allowed the jacket water to leak into the 1-left cylinder.

The licensee determined the root cause was subpar mechanical properties of the liner causing the cylinder liner to crack which allowed jacket water to leak into the diesels lubrication oil. To prevent recurrence of this event, the stations test methods shall be specified to ensure that liners currently in inventory have sufficient material tensile strength to conform to the requirements. A report that details the test method used and the results of testing shall be reviewed prior to any liner from inventory being installed in either diesel generator 1 or 2.

The Licensee Event Report is closed.

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Report (LER) 05000298/2014-003-00, Valve Linkage Pin Out

of Position Causes Condition Prohibited by Technical Specifications

a. Inspection Scope

On February 25, 2014, during planned reactor core isolation cooling system maintenance activities, a linkage pin in the reactor core isolation cooling trip and throttle valve, RCIC-MOV-MO14, was found out of position and not properly restrained. The pin is part of the linkage assembly that ensures a successful valve reset following normal reactor core isolation cooling turbine trip situations. With the linkage pin in the as-found condition, it may have become disengaged during future reactor core isolation cooling system operation and prevented RCIC-MOV-MO14 from automatically resetting, thus causing a system failure. Investigation found the set screws were loose with no thread locker applied. The cause of the linkage pin being out of position was inadequate work instructions during the valve overhaul in August 2010. The inadequate work instructions led to the set screw being out of position, which eventually let the linkage pin move out of position.

Immediate corrective action was taken to properly reinstall the pin, and RCIC-MOV-MO14 was tested satisfactorily on February 25, 2014. An additional corrective action was completed to revise the associated maintenance plan for RCIC-MOV-MO14 to include guidance for installation of the linkage pin and set screws.

The Licensee Event Report is closed. One Severity Level IV iolation was documented in Section 1R12 of this report.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Temporary Instruction 2515/182 - Review of the Industry Initiative to Control

Degradation of Underground Piping and Tanks

a. Inspection Scope

Leakage from buried and underground pipes has resulted in groundwater contamination incidents with associated heightened NRC and public interest. The industry issued a guidance document, Nuclear Energy Institute Document 09-14, Guideline for the Management of Buried Piping Integrity, (ADAMS Accession No. ML1030901420) to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, the Nuclear Energy Institute issued Revision 1 to Nuclear Energy Institute Document 09-14, Guidance for the Management of Underground Piping and Tank Integrity, (ADAMS Accession No. ML110700122) with an expanded scope of components which included underground piping that was not in direct contact with the soil and underground tanks.

On November 17, 2011, the NRC issued Temporary Instruction 2515/182, Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to gather information related to the industrys implementation of this initiative.

b. Observations The licensees buried piping and underground piping and tanks program was inspected in accordance with Paragraph 03.02.a of the Temporary Instruction and it was confirmed that activities which correspond to completion dates specified in the program which have passed since the Phase 1 inspection was conducted, have been completed.

Additionally, the licensees buried piping and underground piping and tanks program was inspected in accordance with Paragraph 03.02.b of the Temporary Instruction and responses to specific questions were submitted to the NRC headquarters staff. Based upon the scope of the review described above, Phase II of Temporary Instruction 2515/182 was completed.

c. Findings

No findings were identified.

.2 Followup Inspection for the May 2013 Cooper Nuclear Station Independent Safety

Culture Assessment, IP 40100

a. Inspection Scope

In performing the Cooper Nuclear Station independent safety culture assessment followup, Inspection Procedure 40100, the inspection team conducted five focus group interviews, and five individual interviews. The focus groups included Engineers, Maintenance Technicians, Operators, Operation Manages, and Security. Individuals interviewed included the Employee Concerns Program Manager, the Human Resources Manager, the General Manager of Plant Operations, the Nuclear Safety Assurance Director, and a root cause analyst. The team reviewed the May 2013 Cooper Nuclear Station Nuclear Safety Culture Assessment and the corrective actions resulting from that assessment. The team reviewed Cooper Nuclear Station inspection reports since May 2013. The team conducted a snapshot inspection while on site including a review of Cooper Nuclear Stations Daily Operational Focus and a tour of the control room which included an impromptu interview of control room personnel on current issues and operability determinations. Throughout the inspection the inspection team assessed the safety conscious work environment (SCWE) at the site.

b. Assessment

(1) Willingness to Raise Nuclear Safety Issues Focus groups and individual interviews indicated that station personnel do not hesitate in raising nuclear safety concerns. Interviews revealed that management is receptive to concerns and take action to address them. Employees stated that they are encouraged to use the corrective action program (CAP). The corrective action program allows for updates to the concern if the employees believe that the concern is not properly addressed. Employees do not hesitate to raise concerns up the chain of command. Management has an open door policy. Although none of the interviewees indicated the need to escalate safety concerns, they were aware of the Employee Concern Program (ECP) and the availability of the NRC to elevate nuclear safety concerns.

The inspection team concludes that there is a willingness to raise safety concerns at Cooper Nuclear Station.

(2) Employee Concerns Program All the interviewees were aware of the Employee Concerns Program (ECP).

Interviewees did not have personal experience with the Employee Concerns Program because those interviewed indicated that they would bring up concerns to their supervisor, and therefore, do not need to use the program. However, there was a favorable impression of the program and everyone interviewed also stated that they would use the program if needed.

The Employee Concerns Program manager indicated that issues brought to the Employee Concerns Program are of management style in enforcing accountability and not issues of nuclear safety. The issues of management style are assessed and monitored to ensure there is no chilling effect that would preclude personnel raising nuclear safety concerns.

The inspection team concludes that Cooper Nuclear Station has an effective Employee Concerns Program.

(3) Retaliation Interviewees knew of no instances where individuals experienced retaliation or other negative reaction for raising nuclear safety concerns.

The inspection revealed that Cooper Nuclear Station has no formal, proceduralized process to review disciplinary actions for potential safety conscious work environment issues. Disciplinary actions are reviewed on a case by case basis for potential safety conscious work environment issues.

The inspection team concludes that personnel at Cooper Nuclear Station are able to raise nuclear safety concerns without fear of retaliation. However, the team recommends that additional NRC monitoring of Cooper Nuclear Stations safety conscious work environment review of disciplinary actions is warranted given the ad-hoc nature of the review process.

(4) Decision Making Cooper Nuclear Station recently has had several inspection findings associated with operability determinations. The findings contained cross-cutting aspects in the area of human performance associated with the decision-making component because the licensee did not adopt a requirement to demonstrate that the proposed action was safe in order to proceed, rather than a requirement to demonstrate that it was unsafe in order to disapprove the action. Actions have been taken to address this human performance weakness. Operators and engineers have received outside training on the operability determination process.

Operators and engineers admit that past operability determination performance was unacceptable and indicate that this training has been effective in improving operability determination quality. Control room observations of the operability determination process revealed that operability determinations do not burden the on-shift operations staff. Operations personnel responsible for performing operability determinations are not responsible for operational oversight.

Operations personnel performing operability determinations are able to get sufficient support and information as needed to perform operability determinations.

The inspection team concludes that corrective actions have addressed the conservative decision making component of operability determinations. However, the team recommends that continued operability determination monitoring is warranted to ensure sustainability.

(5) Staffing Interviewees indicated that a lack of Senior Reactor Operators (SROs) has placed the station in a staffing crunch that could ultimately affect shift staffing options.

Operators are concerned that if the number of operating crews is reduced, quality of life effects could add stress to the operators. Management is aware of these concerns. There are currently two initial license classes in progress to address this issue.

The inspection team concludes that staffing at Cooper Nuclear Station is adequate.

Station management is taking steps to address potential future short comings, i.e. training more senior reactor operators, and planning a four crew rotation contingency. However, the inspection team recommends that increased monitoring of operation performance is warranted should a four crew rotation be implemented.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 2, 2014, the inspector conducted a telephonic exit meeting to present the results of the in-office inspection of changes to the licensees emergency plan and emergency action levels to Ms. M. Ferguson, Manager, Emergency Preparedness. The licensee acknowledged the issues presented. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

On April 16, 2014, the inspector presented the results of Temporary Inspection 2515/182, Review of Implementation of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to Mr. T. Barker, Manager, Engineering Programs and Components, and other members of the licensees staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. The proprietary information identified was deleted from the NRC computer.

On May 15, 2014, the inspectors presented the results of the follow-up inspection for the May 2013 Cooper Nuclear Station Independent Safety Culture Assessment, IP 40100 to Mr. K. Higginbotham, Plant Manager, and other members of the licensee staff. The staff acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On June 23, 2014, the inspectors presented the inspection results to Mr. O. Limpias, Vice President-Nuclear 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.

On June 26, 2014, the inspectors presented the radiation safety inspection results to Mr. R. Penfield, Director of Nuclear Safety Assurance, 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

T. Barker, Manager, Engineering Programs and Components

J. Bebb, Staff Health Physicist

J. Bednar, Supervisor, Radiation Protection Tech

R. Beilke, Manager, Radiation Protection

J. Dixon, Supervisor, ALARA

M. Ferguson, Manager, Emergency Preparedness

D. Madsen, Senior Staff Engineer, Licensing

B. Thacker, Engineering Programs and Components Supervisor

NRC Personnel

None

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Failure to Correctly Translate Design Requirements into

05000298/2014003-01 NCV Installed Plant Configuration (Section 1R04)

Failure to Report Conditions Prohibited by Technical

05000298/2014003-02 NCV Specifications (Section 1R12)

Failure to Follow Seismic Housekeeping Requirements for

05000298/2014003-03 NCV Scaffolding (Section 1R15)

Closed

Jacket Water Leak into Emergency Diesel Generator Engine

05000298/2014-

LER Results in Condition Prohibited by Technical Specifications and 2-00 Loss of Safety Function (4OA3)

05000298/2014- Valve Linkage Pin Out of Position Causes Condition Prohibited LER 003-00 by Technical Specifications (4OA3)

2515/182 TI Review of the Implementation of the Industry Initiative to Control Degredation of Underground Piping and Tanks (Section 40A5)