IR 05000298/2014002

IR 05000298-14-002; 01/01/2014 - 03/31/2014; Cooper; Integ. Resident & Regl. Rprt; Maint. Risk Assess. & Emerg. Work Control, Op. Determ. & Funct. Assess., Prob. Ident. & Resol., & Follow-up of Events & NOED

ML14135A552
Person / Time
Site:	Cooper
Issue date:	05/15/2014
From:	Allen D NRC/RGN-IV/DRP/RPB-C
To:	Limpias O Nebraska Public Power District (NPPD)
References
IR-14-002
Download: ML14135A552 (39)

Text

UNITED STATES May 15, 2014

SUBJECT:

COOPER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000298/2014002

Dear Mr. Limpias:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Cooper Nuclear Station. On April 1, 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.

Four findings of very low safety significance (Green) are documented in this report. All of these findings involved violations of NRC requirements. One of these violations was determined to be Severity Level IV under the traditional enforcement process. 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 the 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/

Donald B. Allen, Branch Chief Project Branch C Division of Reactor Projects Docket No.: 50-298 License No: DPR-46

Enclosure:

Inspection Report 05000298/2014002 w/ Attachment: Supplemental Information

REGION IV==

Docket: 05000298 License: DPR-46 Report: 05000298/2014002 Licensee: Nebraska Public Power District Facility: Cooper Nuclear Station Location: 72676 648 A Ave Brownville, NE Dates: January 1 through March 31, 2014 Inspectors: J. Josey, Senior Resident Inspector C. Henderson, Resident Inspector P. Elkmann, Senior Emergency Preparedness Inspector Approved Donald B. Allen By: Chief, Project Branch C Division of Reactor Projects-1- Enclosure

SUMMARY

IR 05000298/2014002; 01/01/2014 - 03/31/2014; COOPER NUCLEAR STATION; Integ.

Resident & Regl. Rprt; Maint. Risk Assess. & Emerg. Work Control, Op. Determ. & Funct.

Assess., Prob. Ident. & Resol., & Follow-up of Events & NOED.

The inspection activities described in this report were performed between January 1 and March 31, 2014, by the resident inspectors at the Cooper Nuclear Station and an inspector from the NRCs Region IV Office. Four findings of very low safety significance (Green) are documented in this report. All of these findings involved violations of NRC requirements.

Further, NRC inspectors documented in this report a Severity Level IV violation with an 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, Components Within the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a non-cited violation of 10 CFR 50.65(a)(4),

Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees failure to implement required risk management actions for maintenance activities affecting the flow paths credited in the internal flooding analysis on elevation 903 feet of the reactor building. The station initiated the following corrective actions for this issue: (1) provided a seminar on the requirements of Station Procedure 0-Barrier, Barrier Control Process, to station personnel; and (2) revised maintenance work order walk down checklist pre-job brief to determine whether barrier control permits are required. The licensee entered this deficiency into their corrective action program for resolution as Condition Report CR-CNS-2014-00117.

The licensees failure to implement required risk management actions during maintenance activities 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. Using Inspection Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005, Flowchart 2, Assessment of Risk Management Actions, the inspectors determined the need to calculate the risk deficit to determine the significance of this issue. It was determined that the incremental core damage probability associated with this finding was less than 1 x 10-6; therefore, this finding is determined to have very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance associated with procedure adherence because the licensee failed to follow processes, procedures, and work instructions [H.8] (Section 1R13).

Green.

The inspectors identified two examples of a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with the licensees failure to perform an adequate operability determination in accordance with Station Procedure 0.5OPS, Operations Review of Condition Reports/Operability Determination. Specifically, the licensee failed to adequately evaluate the effect on operability for (1) taking electrical relays out of their seismically qualified configuration and (2) a degraded nonconforming condition created by using non-design bases inputs in a design bases analysis. To correct the first issue, the licensee will declare the service water pumps inoperable during activities that involve opening the switchgear doors and to correct the second issue, the licensee performed subsequent analyses using Manual Chapter 0326, Section C.10, guidance to demonstrate a reasonable expectation of operability. The licensee entered these deficiencies into their corrective action program for resolution as Condition Reports CR-CNS-2014-00464, and CR-CNS-2014-01109.

The failure to properly assess and document the basis for operability when degraded or nonconforming conditions are identified 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 affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to properly assess and document the basis for operability resulted in conditions of unknown operability for degraded nonconforming conditions. 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 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 technical specification 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 nontechnical 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 conservative bias because individuals did not use decision-making practices that emphasize prudent choices over those that are simply allowable to ensure that a proposed action was determined to be safe in order to proceed, rather than unsafe in order to stop [H.14](Section 1R15).

Cornerstone: Barrier Integrity

Green.

Inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.4.1.a, associated with the licensees failure to follow station procedures which resulted in secondary containment inoperability. Specifically, on January 6, 2014, a station operator failed to follow Station Procedure 0.9, Tagouts, and closed the wrong valve while hanging a clearance order to support maintenance. This resulted in an unexpected rise in the reactor buildings differential pressure, which caused the secondary containment to be declared inoperable when pressure went above negative 0.25 inches of water. The corrective action for this issue was to open the mispositioned valve, which restored secondary containment differential pressure.

The licensee entered this deficiency into their corrective action program as Condition Report CR-CNS-2014-00062.

The failure to follow Station Procedure 0.9 while hanging a clearance order 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 affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. 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 was of very low safety significance (Green)because the finding only represented a degradation of the radiological barrier function for the reactor building. The finding has a cross-cutting aspect in the area of human performance associated with avoiding complacency because individuals failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes, which resulted in individuals not implementing appropriate error reduction tools [H.12](Section 4OA3).

Other Findings

and Violations

• Severity Level IV/Green. Inspectors identified a non-cited violation of 10 CFR 50.59,

Changes, Test, and Experiments, and associated Green finding, associated with the licensees failure to adequately evaluate changes to determine if prior NRC approval is required. Specifically, from 1987 through February 11, 2014, the licensee failed to obtain a license amendment pursuant to Section 50.90 prior to implementing a proposed change that would result in a departure from a method of evaluation described in the Updated Safety Analysis Report. This does not represent an immediate safety concern because the licensee performed an operability assessment for the potentially undersized expansion anchors, which established a reasonable expectation for operability pending resolution of the identified issue. The licensee entered this deficiency into their corrective action program as Condition Report CR-CNS-2014-00776.

The licensees failure to implement the requirements of 10 CFR 50.59 and adequately evaluate changes to determine if prior NRC approval is required 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. In accordance with Section 2.1.3.E.6 of the NRC Enforcement Manual, inspectors evaluated this finding using the significance determination process to assess its significance. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the finding was determined to have very low safety significance (Green) because it: (1) was not a deficiency affecting the design or 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 technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; (4) did not represent an actual loss of function of one or more nontechnical specification trains of equipment designated as high safety-significance in accordance with the licensees maintenance rule program; and (5) did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather event.

Therefore, in accordance with Section 6.1.d.2 of the NRC Enforcement Policy, inspectors characterized this performance deficiency as a Severity Level IV violation.

There was no cross-cutting aspect assigned to this finding because this issue does not reflect present licensee performance (Section 4OA2).

PLANT STATUS

The Cooper Nuclear Station began the inspection period at full power on January 1, 2014. On March 10, 2014, the licensee lowered power to approximately 11 percent to affect repairs to main turbine stop valve 1 solenoid operated valve MS-SOV-SLV2 and relief valve TGF-RV-15RV and perform scheduled maintenance on reactor recirculation motor generators A and B. On March 14, 2014, reactor power was increased to 100 percent and remained at essentially full power for the remainder of the reporting period.

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 March 12, 2014, the inspectors completed an inspection of the stations readiness to cope with external flooding. After reviewing the licensees flooding analysis, the inspectors chose the control building, elevation 903 feet and basement, that was susceptible to flooding.

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 walk-downs of the following risk-significant systems:

• January 14, 2014, Service water residual heat removal, Division I

• February 3, 2014, Residual heat removal pumps and fan coil units, Division II

• March 31, 2014, Turbine building blowout panels 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 walk-down samples as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Inspection

a. Inspection Scope

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

• January 15, 2014, Control building, 882 feet 6 inches, Fire Area IV, Zone 7A, residual heat removal service water, Division II, hotwork area

• February 6, 2014, Reactor building, 903 feet, northeast corner, Fire Area I, Zone 2A

• February 6, 2014, Control building, 903 feet corridor, Fire Area V, Zone 8D

• March 6, 2014, Reactor protection system Room 1B, Fire Area IV, Zone 8F 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 March 31, 2014, 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 two plant areas containing risk-significant structures, systems, and components that were susceptible to flooding:

• February 5, 2014, Service water pump room

• March 31, 2014, Reactor building, 903 feet north 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.

In addition, on March 31, 2014, the inspectors completed an inspection of underground bunkers susceptible to flooding. The inspectors selected two manholes that contained risk-significant or multiple-train cables whose failure could disable risk-significant equipment:

• Manhole 12

• Manhole 13 The inspectors observed the material condition of the cables and splices contained in the manholes and looked for evidence of cable degradation due to water intrusion. The inspectors verified that the cables and vaults met design requirements.

These activities constitute completion of two flood protection measures samples and one bunker/manhole sample, as defined in Inspection Procedure 71111.06.

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 January 29, 2014, 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.

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 March 15, 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 repair and maintenance activities. The inspectors observed the operators performance of the following activities:

• Removing turbine generator from services for repairs

• Restoration from single loop operation after schedule reactor recirculation motor generator A and B maintenance 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 two instances of degraded performance or condition of safety-related structures, systems, and components:

• January 23, 2014, Torus high level alarm credited for internal flooding analysis

• February 20, 2014, Credited external flooding mitigating equipment and barriers 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 structures, systems, or components. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.

These activities constituted completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.

b. Findings

No findings were identified.

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:

• January 7, 2014, Standby liquid control A maintenance yellow risk window

• January 15, 2014, Residual heat removal and residual heat removal service water, Division II, maintenance window

• February 7, 2014, Scram discharge volume vent and drain valve position indicator and in-service test surveillances

• February 12, 2014, Reactor equipment cooling and service water motor-operated valve electrical and mechanical exams 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 cause an initiating event and to affect the functional capability of mitigating systems.

• March 11, Turbine control valve 1 repair

• March 28, High pressure coolant injection unavailable and station startup service transformer inoperable 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 constitute completion of six maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees failure to implement required risk management actions for maintenance activities affecting the flow paths credited in the internal flooding analysis on elevation 903 feet of the reactor building.

Description.

Inspectors reviewed the risk assessment and specified risk management actions associated with maintenance activities conducted on December 30, 2013, in the general area on elevation 903 feet of the reactor building under Work Orders 4978869 and 4910386, which included Barrier Control Permit 2013-0292. This work was conducted outside of flow paths credited in the internal flooding analysis for elevation 903 feet of the reactor building. The inspectors noted that to manage the risks associated with the maintenance activities, Barrier Control Permit 2013-0292 required the restraint of material/equipment to prevent blockage of credited flow paths and a continuous non-independent flood watch.

The inspectors reviewed Station Procedure 0-Barrier, Barrier Control Process, Revision 10, to verify that Barrier Control Permit 2013-0292 implemented the procedurally required risk management actions for maintenance activities in this location.

Inspectors noted that Attachment 14, Flooding Barriers, Section 5.5.1.9, required that all activities in areas outside of the credited flow path of the internal flooding analysis, for the general area of elevation 903 feet of the reactor building, have an independent continuous flood watch with no other assigned duties. Therefore, inspectors determined that the non-independent continuous flood watch required in Barrier Control Permit 2013-0292 was contrary to what was required in Station Procedure 0-Barrier because this individual had other duties assigned and was not able to continuously monitor the impacted area. Inspectors determined that this was a failure to implement procedurally required risk management actions. Inspectors informed the licensee of their concern, and the licensee initiated Condition Report CR-CNS-2014-00117 to capture this issue in the stations corrective action program.

The licensees evaluation determined that: 1) activities performed outside the work order process have the possibility of requiring barrier control permits (i.e., radiation protection postings and chemistry sampling activities) and 2) some work orders in the work control process (surveillance activities) do not receive reviews by the stations planners or the work control center personnel. The licensee initiated the following corrective actions:

(1) provided a seminar on the requirements of Station Procedure 0-Barrier to station personnel and

(2) revised maintenance work order walk-down checklist pre-job brief to determine whether barrier control permits are required.

Inspectors determined that the apparent cause of this finding was the licensees failure to follow Station Procedure 0-Barrier requirements to implement required risk management actions for maintenance activities associated with Work Orders 4978869 and 4910386.

Analysis.

The licensees failure to implement required risk management actions during maintenance activities 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. Using Inspection Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005, Flowchart 2, Assessment of Risk Management Actions, the inspectors determined the need to calculate the risk deficit to determine the significance of this issue. It was determined that the incremental core damage probability associated with this finding was less than 1 x 10-6; therefore, this finding is determined to have very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance associated with the procedure adherence component because the licensee failed to follow processes, procedures, and work instructions [H.8].

Enforcement.

Title 10 CFR 50.65(a)(4) states, in part, Before performing maintenance activities (including, but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from proposed maintenance activities. Contrary to the above, on December 30, 2013, the licensee failed to properly manage the increase in risk that resulted from proposed maintenance activities. Specifically, the licensee failed to implement procedurally required risk management actions for maintenance activities affecting the flow paths credited in the internal flooding analysis on elevation 903 feet of the reactor building. Because the finding was of very low safety significance (Green)and has been entered into the corrective action program as Condition Report CR-CNS-2014-00117, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000298/2014002-01, Failure to Implement Risk Management Actions for Maintenance Activities)

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed six operability determinations and functionality assessments that the licensee performed for degraded or nonconforming structures, systems, or components:

• January 22, 2014, Operability determination of the emergency core cooling system for mitigating internal flooding for the northwest, northeast, and southeast quads from a 10-inch fire protection line break

• January 23, 2014, Operability determination of the residual heat removal, Division II, RHR-MOV-25B tripper finger spring and manual operation

• January 29, 2014, Functionality assessment of control building Door H100 external flooding barrier

• February 13, 2014, Operability determination of the building and removal of scaffolding around safety-related systems, structures, and components

• February 20, 2014, Operability determination of service water pump B during 4160 Vac, Bus 1G undervoltage testing

• March 10, 2014, Operability determination of the use of 5000 psi concrete for safety-related anchorages The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded structures, systems, or components to be operable or functional, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability or functionality. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability or functionality of the degraded structure, system, or component.

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

b. Findings

Introduction.

The inspectors identified two examples of a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with the licensees failure to perform an adequate operability determination in accordance with Station Procedure 0.5OPS, Operations Review of Condition Reports/

Operability Determination.

Description.

Station Procedure 0.5OPS, Operations Review of Condition Reports/Operability Determinations, Revision 46, provided the guidance used by operations staff at the Cooper Nuclear Station to perform operability determinations.

Section 3.1 required, in part, that the shift manager, document the basis for operability when a degraded or nonconforming condition exists. The failure to properly assess degraded non-conforming conditions has the potential to result in structures, systems and components not being able to perform its specified safety function (inoperable) and not recognized as such by the operators.

Inspectors identified two examples of inadequate operability determinations that had been performed by the licensee.

Example 1: On January 20, 2014, the licensee performed a maintenance activity which involved opening the cabinet doors on the G bus of the 4160 Vac switchgear. Opening the doors affects seismic qualification of the high pressure trip relay associated with the auto position of the service water pumps on the G bus. Specifically, with the door open the relay has the potential to change state during a seismic event which would affect the ability of the pump to start on a low pressure signal, as required by Technical Specifications.

Operators, recognizing that the maintenance activity affected the operability of the relays, assessed this condition and documented the following as the basis for operability in the operators logs on January 20, 2014:

Operations and Maintenance personnel will be performing SP 6.2EE.302 this morning which opens the upper cubicle doors on several 4160G breakers. The Under Voltage function of all affected relays remains available during this surveillance. Under Voltage relays have not been analyzed for seismic impact with the cubicle doors in the open position and will be declared inoperable until the affected doors are closed at the end of the surveillance. Service Water relays SW-REL-63DL1G and SW-REL-63DH1G are mounted on SW-P-B breaker cubicle which will also be opened during this surveillance. These relays would potentially be impacted by a seismic event. The duration of the seismic event is assumed to be 30 seconds long. Although unlikely, during this seismic event, the SW relays may experience relay chatter. Both relays are mounted on the same cubicle door, one on top of the other, and would experience shaking in the same direction. For this reason, the affected Service Water pump will not receive a start and stop signal at the same time. If the AUTO pump were to trip for the duration of the seismic event (30 seconds) it will result in a low pressure condition that will restart the pump after the seismic event is over provided normal power is available. In the event of a loss of off-site power, the AUTO pump does not start on restoration of emergency power. The STAND_BY pump will automatically start during sequential loading after emergency power is restored to the bus. There will be no adverse impact to the service water system from this occurrence. Division 2 Service Water is not rendered inoperable with SW-P-B cubicle door in the open position.

Inspectors questioned the operators assessment because they noted that this evaluation identified that the high pressure trip relay could chatter, which would prevent the affected pump from starting, but had determined that operability was not affected.

During subsequent discussions with operations personnel, inspectors were told that the assessment was based classifying the relays as non-essential in accordance with EPRI-NP-7148-SL, Procedure for Evaluating Nuclear Power Plant Relay Seismic functionality.

Inspectors determined that the licensees assessment was not correct. Specifically, Technical Specification Surveillance Requirement 3.7.2.4, required the licensee to verify that the service water pumps would start on a low pressure signal when in the auto position, and the stations Updated Safety Analysis Report specifically specified that relays in the G bus must be capable of withstanding the specified seismic conditions without any failure and without false tripping or closing of relays. Therefore, inspectors determined that the relays should have been declared inoperable during the maintenance activity.

Inspectors informed the licensee of their concern and the licensee entered this issue in the stations corrective action program as Condition Report CR-CNS-2014-00464.

Subsequently, the licensee determined that their assessment was not adequate.

Inspectors noted that the maintenance activities duration was less than the technical specification allowed outage time for the pump. During future surveillance activities that involve opening the switchgear doors, the licensee will declare the service water pump inoperable pending further engineering evaluation.

Example 2: On February 12, 2014, the licensee documented an operability assessment associated with the use of non-design bases values in design bases analyses (NCV 05000298/2014002-03, Failure to Evaluate Changes to Ensure They Did Not Require Prior Approval). Specifically, the licensee had inappropriately used 5000 psi for compressive strength of concrete when evaluating expansion anchor bolts sizing, instead of 3500 psi as document in the facilities Updated Safety Analysis Report, which resulted in potentially undersized expansion anchors being installed in the facility. In their operability assessment the licensee continued to use 5000 psi as the compressive strength for concrete based on:

(1) having testing data that supported this value and

(2) Inspection Manual Chapter 0326, Operability Determinations & Functionality Assessments for Conditions Adverse to Quality or Safety, Appendix C, Section C.10, Piping and Pipe Support Requirements.

Inspectors reviewed the stations Updated Safety Analysis Report and Inspection Manual Chapter 0326. During their reviews, inspectors noted the following: Inspection Manual Chapter 0326, Section C.10, did provide criteria for assessing the operability of degraded anchor bolts. Specifically, it referred users to the guidance provided in Bulletin 79-02, Pipe Support Base Plate Designs Using Concrete Expansion Anchor Bolts, which allowed for a reduction in the safety factor of the anchor bolts. The Updated Safety Analysis Report stated that the licensee was committed to ACI 318-63, Building Code Requirements for Reinforced Concrete. ACI 318-63 provides acceptance limits for concrete design using the compressive strength of the concrete specified at the time of construction as indicated by design drawings or specifications.

The stations Updated Safety Analysis Report specified a compressive strength based on 28-day testing results (3500 psi) as the design basis to be used for concrete.

Based on the above, inspectors concluded that the documented operability evaluation had failed to evaluate the identified degraded condition, potentially undersized expansion anchor bolts. Inspectors informed the licensee of their concern and the licensee initiated Condition Report CR-CNS-2014-01109 to capture this issue in the stations corrective action program. The licensee subsequently performed an adequate operability assessment using Inspection Manual Chapter 0326, Section C.10, guidance which established a reasonable expectation of operability.

Analysis.

The failure to properly assess and document the basis for operability when a degraded or nonconforming condition was identified 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 affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to properly assess and document the basis for operability for the two examples resulted in a condition of unknown operability for degraded nonconforming conditions. 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 was of very low safety significance (Green) because, in both examples, 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 technical specification 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 nontechnical 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 the conservative bias component because individuals did not use decision-making practices that emphasize prudent choices over those that are simply allowable to ensure that a proposed action was determined to be safe in order to proceed, rather than unsafe in order to stop [H.14].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be accomplished in accordance with documented instructions, procedures, or drawings, of a type appropriate to the circumstances.

Station Procedure 0.5OPS, Operations Review of Condition Reports/Operability Determination, a procedure that is appropriate to the circumstances of evaluating the operability of safety-related components, required the licensee to properly assess and document the basis for operability when a degraded or nonconforming condition was identified. Contrary to the above, on January 20, and February 12, 2014, an activity affecting quality was not accomplished in accordance with a procedure that was appropriate to the circumstances. Specifically, operators failed to adequately evaluate the effect on operability of; taking electrical relays for the service water pumps out of their seismically qualified configuration, and potentially undersized expansion anchor bolts. 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 correction action program as Condition Reports CR-CNS-2014-00122 and CR-CNS-2014-01109. (NCV 05000298/2014002-02, Failure to Follow Operability Procedure)

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed two permanent plant modifications that affected risk-significant structures, systems, and components:

• March 10, 2014, Residual heat removal service water pump B/D cell service water modification, Division II

• March 31, 2014, Diesel generator solenoid operated valve fusing The inspectors reviewed the design and implementation of the modifications. The inspectors verified that work activities involved in implementing the modifications did not adversely impact operator actions that may be required in response to an emergency or other unplanned event. The inspectors verified that post-modification testing was adequate to establish the operability of the structures, systems, and components as modified.

These activities constitute completion of two samples of permanent modifications, as defined in Inspection Procedure 71111.18.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed five post-maintenance testing activities that affected risk-significant structures, systems, or components:

• January 21, 2014, Residual heat removal B maintenance window

• January 21, 2014, Residual heat removal service water piping repair, Division II

• February 13, 2014, Reactor equipment cooling and service water motor-operated valve electrical and mechanical exams

• February 27, 2014, Reactor core isolation cooling limiting condition for operation maintenance window

• March 25, 2014, Diesel generator 2 limiting condition for operation maintenance window The inspectors reviewed licensing- and design-basis documents for the structures, systems, or 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, or components.

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

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

In-service tests:

• January 22, 2014, Residual heat removal, Division II, RHR-MOV-38B Other surveillance tests:

• January 8, 2014, Scram discharge volume vent and drain valve position indicator

• February 7, 2014, Reactor equipment cooling pumps time delay relay testing, Division I

• March 7, 2014, Diesel generator 1 operability test with isolation switches in isolate

• March 21, 2014, Diesel generator 2 fuel oil tank level switches functional test and solenoid valve in-service testing closure test The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the 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 five 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 Report 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.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors observed an emergency preparedness drill on January 28, 2014, to verify the adequacy and capability of the licensees assessment of drill performance. The inspectors reviewed the drill scenario; observed the drill from the control room, the operational support center, and the technical support center; and attended the post-drill critique. The inspectors verified that the licensees emergency classifications, off-site notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the licensee in the post-drill critique and entered into the corrective action program for resolution.

These activities constitute completion of one emergency preparedness drill observation sample, as defined in Inspection Procedure 71114.06.

b. Findings

No findings were identified.

.2 Training Evolution Observation

a. Inspection Scope

On January 28, 2014, 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, off-site 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 constitute completion of one training observation sample, as defined in Inspection Procedure 71114.06.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours (IE01)

a. Inspection Scope

The inspectors reviewed licensee event reports (LERs) for the period from the first quarter 2013 through the fourth quarter 2013 to determine the number of scrams that occurred. The inspectors compared the number of scrams reported in these licensee event reports to the number reported for the performance indicator. Additionally, the inspectors sampled operating logs to verify the number of critical hours during the period. 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 data reported.

These activities constituted verification of the Unplanned Scrams per 7000 Critical Hours performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Unplanned Power Changes per 7000 Critical Hours (IE03)

a. Inspection Scope

The inspectors reviewed operating logs and corrective action program records for the period from the first quarter 2013 through the fourth quarter 2013 to determine the number of unplanned power changes that occurred. The inspectors compared the number of unplanned power changes documented to the number reported for the performance indicator. Additionally, the inspectors sampled operating logs to verify the number of critical hours during the period. 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 data reported.

These activities constituted verification of the Unplanned Power Changes per 7000 Critical Hours 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 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected two issues for an in-depth follow-up:

• On January 7, 2014, the inspectors reviewed control room deficiencies to ensure that the licensee is identifying operator work around problems.

The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to correct the condition.

• The licensees use of 5000 psi as the compressive strength for concrete when sizing expansion anchor bolts.

The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to correct the condition.

These activities constitute completion of two annual follow-up samples, which included one operator work-around sample, as defined in Inspection Procedure 71152.

b. Findings

Introduction.

Inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.59, Changes, Test, and Experiments, and associated Green finding, associated with the licensees failure to adequately evaluate changes to determine if prior NRC approval is required.

Description.

On September 6, 2012, the NRC issued Information Notice 2012-017, Inappropriate Use of Certified Material Test Report Yield Stress and Age-Hardened Concrete Compressive Strength In Design Calculations. The purpose of this Information Notice was to provide operating experience related to the use of non-design bases information in design applications. Two of the identified examples involved issues where facilities had deviated from their Updated Safety Analysis Report with respect to their code of record for concrete, ACI 318, Building Code Requirements for Reinforced Concrete. Specifically, the Updated Safety Analysis Report stated that the compressive strength of concrete was based on 28-day testing as specified by ACI 318.

The licensee initiated Condition Report CR-CNS-2012-06405 to evaluate Information Notice 2012-017. In their evaluation, the licensee identified that 5000 psi was being used as the concrete compressive strength for expansion anchors. The evaluation referred to Updated Safety Analysis Report, Appendix C, Structural Loading Criteria, which stated that this was acceptable because the stations response to Bulletin 79-02, Pipe Support Base Plate Designs Using Concrete Expansion Anchor Bolts, had been based on concrete strength of 5000 psi, which had been determined by actual 90-day testing. Therefore, the licensee concluded that the issues identified with the use of non-design values were not applicable to the Cooper Nuclear Station.

Inspectors reviewed the licensees evaluation and questioned the conclusion.

Specifically, inspectors noted that the stations Updated Safety Analysis Report stated that the licensee was committed to ACI 318-63, Building Code Requirements for Reinforced Concrete. ACI 318-63, Section 504, Strength Tests of Concrete, specifies that the age for strength testing of concrete shall be 28 days or sooner. Inspectors noted that FSAR Question 12.8 and Appendix C of the stations Updated Safety Analysis Report specified a compressive strength based on 28-day testing results (3000 psi) as the design basis to be used for all concrete except for expansion anchors. Inspectors noted that Appendix C, Section 2.5.10, Concrete Attachments, had been changed to allow the licensee to use 90-day test data (5000 psi) when calculating anchor bolt allowables. This was documented as being based on vendor report that was supplied to the station in response to Bulletin 79-02. Inspectors also reviewed Bulletin 79-02 and noted that it directed licensees to verify that concrete expansion anchors met safety factor requirements, and if they did not, then develop corrective actions to restore compliance. The bulletin did not address/authorize changing design bases information through responses.

Inspectors asked the licensee by what process had the stations Updated Safety Analysis Report been changed to incorporate the use of 90-day test data (5000 psi) for expansion anchors. Specifically, had the 10 CFR 50.59 process been followed. The licensee determined that a 10 CFR 50.59 evaluation had not been performed, but stated that the NRC had approved this change, as noted in a February 5, 1980, bulletin response letter, and in response to a 1987 Updated Safety Analysis Report update that the station had submitted.

Inspectors reviewed the documents identified by the licensee. With respect to the Bulletin response letter the licensee submitted on February 5, 1980, inspectors determined that the licensee had not used 5000 psi as the compressive strength for concrete expansion anchors. Instead the letter stated, in part, following the upcoming refueling outage, the licensees architect-engineer intended to evaluate increasing the compressive strength for concrete based on actual 90-day test data.

With respect to the licensees submittal for the Updated Safety Analysis Report update from July 22, 1987, inspectors determined that this update detailed five changes that had been made under 10 CFR 50.59 that had not been previously submitted to the NRC, as well as some major changes that the NRC had been informed of. The inspectors noted that none of the described changes recognized or identified that a change was made in regard to concrete compressive strength with respect to anchor bolting.

Inspectors also noted that the NRC acceptance letter dated November 25, 1987, did not identify the changes in concrete strength as being reviewed and accepted either.

Therefore, inspectors determined that the NRC had not previously reviewed and approved this change.

Based on the above, inspectors determined that the licensee had failed to evaluate a change being made to the stations Updated Safety Analysis Report as required by 10 CFR 50.59. Inspectors determined that this change would have required prior approval under both the old and new 10 CFR 50.59 process. Inspectors determined that this change represented a change in method of evaluation described in the Updated Safety Analysis Report.

Inspectors informed the licensee of their determination and the licensee initiated Condition Report CR-CNS-2014-00776 to capture this issue in the stations corrective action program for resolution. The licensee performed a subsequent operability assessment, which established a reasonable expectation for operability pending resolution of the identified issue.

Analysis.

The licensees failure to implement the requirements of 10 CFR 50.59 and adequately evaluate changes to determine if prior NRC approval is required 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. In accordance with Section 2.1.3.E.6 of the NRC Enforcement Manual, inspectors evaluated this finding using the significance determination process to assess its significance. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the finding was determined to have very low safety significance (Green) because it

(1) was not a deficiency affecting the design or 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 technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time;

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

(5) did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather event.

Therefore, in accordance with Section 6.1.d.2 of the NRC Enforcement Policy, inspectors characterized this performance deficiency as a Severity Level IV violation.

There was no cross-cutting aspect assigned to this finding because this issue does not reflect present licensee performance.

Enforcement.

Title 10 CFR 50.59, Changes, Tests, and Experiments, Section (c)(1),states, in part, that a licensee may make changes in the facility as described in the Updated Safety Analysis Report without obtaining a license amendment pursuant to 10 CFR 50.90 only if:

(i) a change to the technical specifications incorporated in the license is not required, and

(ii) the change, test, or experiment does not meet any of the criteria in paragraph (c)(2). Title 10 CFR 50.59, Section (c)(2), states, in part, that a licensee shall obtain a license amendment pursuant to Section 50.90 prior to implementing a proposed change, test, or experiment if the change, test, or experiment would result in a departure from a method of evaluation described in the Updated Safety Analysis Report used in establishing the design bases or in the safety analyses.

Contrary to the above, from 1987 until February 11, 2014, the licensee failed to obtain a license amendment pursuant to Section 50.90 prior to implementing a proposed change, test, or experiment if the change, test, or experiment would result in a departure from a method of evaluation described in the Updated Safety Analysis Report. Because this violation was entered into the corrective action program as Condition Report CR-CNS-2014-00776 to ensure 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 05000298/2014002-03, Failure to Evaluate Changes to Ensure They Did Not Require Prior Approval)

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

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

(Closed) Licensee Event Report (LER) 05000298/2014001-00, Secondary Containment Declared Inoperable due to Rise in Differential Pressure

a. Inspection Scope

On January 6, 2014, the differential pressure in the reactor building unexpectedly raised above negative 0.25 inches of water. This caused; entry into Limiting Condition of Operation 3.6.4.1, Condition A, and declaring secondary containment inoperable.

This transient occurred when a non-licensed operator was hanging tags in support of maintenance activities and inadvertently opened the wrong drain valve. This resulted in the operating reactor recirculation motor generator exhaust fan discharge damper closing, which caused secondary containment differential pressure to rise. The non-licensed operator felt the change in differential pressure and closed the drain valve, which opened the reactor recirculation motor generator exhaust fan discharge damper, and restored ventilation. Secondary containment was subsequently declared operable, and the station exited the limiting condition of operation.

The licensee determined the root cause was that the station was not fully aware of the effects of the cross-over leakage between the reactor building envelope and the reactor recirculation motor generator exhaust system. To prevent recurrence of this event, station procedures are to be revised to ensure adequate precautions are taken to avoid exceeding -0.25 inches of water column differential pressure requirement for secondary containment, information concerning effects of cross-over leakage are to be incorporated into appropriate training material, and a procedure to directly measure air leakage between the reactor building and reactor recirculation motor generator exhaust system is to be developed.

This Licensee Event Report is closed. One non-cited violation of NRC requirements was identified.

b. Findings

Introduction.

Inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.4.1.a, associated with the licensees failure to follow station procedures which resulted in secondary containment inoperability.

Description.

On January 6, 2014, a station operator was hanging a clearance order in accordance with Station Procedure 0.9, Tagout, Revision 84, to support planned maintenance on reactor recirculation motor generator ventilation components. While hanging the clearance order the operator failed to verify that the correct component was being manipulated, as required by Section 9.4 of Procedure 0.9. This resulted in an unexpected rise in the reactor buildings differential pressure, which caused the secondary containment to be declared inoperable when pressure went above

-0.25 inches of water. Subsequently, the operator recognized the mistake and corrected the component misposition which re-established reactor building differential pressure to less than -0.25 inches of water. The licensee initiated Condition Report CR-CNS-2014-00062 to capture this issue in the stations corrective action program for resolution.

The licensee performed a root cause analyses for this issue, as documented in Condition Report CR-CNS-2014-00062. During their evaluation, the licensee determined that the operator had mispositioned the component due to human error. The licensee also determined that this error had revealed a previously unrecognized system interaction that had the potential to affect secondary containment. The licensee went on to determine that the root cause of this issue was, The organization was not fully aware of the effects of the inter-relationship (cross leakage) between the reactor building envelope and the reactor recirculation motor generator HVAC exhaust system since it was not captured in applicable plant documents (procedures and training), which affected their ability to identify the potential to impact containment differential pressure, and the contributing cause was, The organization failed to recognize the potential for increased human error due to the aggregate effect of a combination of human error precursors.

Inspectors reviewed the licensees cause evaluation and determined that it was adequate.

Analysis.

The failure to follow Station Procedure 0.9 while hanging a clearance order 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 affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. 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 was of very low safety significance (Green)because the finding only represented a degradation of the radiological barrier function for the reactor building. The finding has a cross-cutting aspect in the area of human performance associated with the avoiding complacency component because individuals failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes, which resulted in individuals not implementing appropriate error reduction tools [H.12].

Enforcement.

Technical Specification 5.4.1.a requires implementation of applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 1(c) of the Appendix requires procedures for equipment control (e.g., locking and tagging). Station Procedure 0.9, Tagout, implemented this requirement and Section 9.4 required that personnel verify that the correct component is being manipulated. Contrary to the above, on January 6, 2014, a station operator failed to verify that the correct component was being manipulated while hanging a clearance order. The operator recognized the mistake and corrected the component misposition which re-established reactor building differential pressure to less than -0.25 inches of water. 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 correction action program as Condition Report CR-CNS-2014-00122.

(NCV 05000298/2014002-04, Failure to Follow Tagout Procedure)

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 1, 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 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.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Austin, Training Manager

T. Barker, Manager, Engineering Programs and Components

J. Bebb, Staff Health Physicist, Radiation Protection

J. Bednar, Technical Supervisor, Radiation Protection

R. Beilke, Manager, Radiation Protection

D. Buman, Director, Engineering

T. Chard, Manager, Quality Assurance

S. DeRosier, Operator Training Superintendent

J. Dixon, ALARA Supervisor, Radiation Protection

R. Estrada, Manager, Design Engineering

M. Ferguson, Manager, Emergency Preparedness

J. Florence, Simulator Supervisor

C. Herring, Superintendent, Operations Training, Requalification

K. Higginbotham, General Plant Manager, Operations

K. Fike, Plant Chemist, Chemistry

J. Flaherty, Senior Staff Licensing Engineer, Licensing

E. Jackson, Exam Developer

D. Madsen, Senior Staff Engineer, Licensing

R. Morris, Specialist, Radiation Protection

J. Olberding, Licensing Specialist

R. Penfield, Director Nuclear Safety Assurance

J. Stough, Manager, Information Technology

K. Tanner, Radiological Shift Supervisor, Radiation Protection

D. Van Der Kamp, Manager, Licensing

A. Walters, Manager, Chemistry

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000298/2014002-01 NCV Failure to Implement Risk Management Actions for Maintenance Activities (Section 1R13)

05000298/2014002-02 NCV Failure to Follow Operability Procedure (Section 1R15)

05000298/2014002-03 NCV Failure to Evaluate Changes to Ensure They Did Not Require Prior Approval (Section 4OA2)

05000298/2014002-04 NCV Failure to Follow Tagout Procedure (Section 4OA3)

Closed

05000298/2014001-00 LER Secondary Containment Declared Inoperable due to Rise in Differential Pressure (Section 4OA3)

Attachment