IR 05000282/2015007

IR 05000282/2015007, 05000306/2015007; 08/03/2015 - 09/04/2015; Prairie Island Nuclear Generating Plant, Units 1 and 2; Component Design Bases Inspection

ML15288A195
Person / Time
Site:	Prairie Island
Issue date:	10/14/2015
From:	Christine Lipa NRC/RGN-III/DRS/EB2
To:	Davison K Northern States Power Co
References
IR 2015007
Download: ML15288A195 (35)

Text

UNITED STATES ber 14, 2015

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 NRC COMPONENT DESIGN BASES INSPECTION; INSPECTION REPORT 05000282/2015007; 05000306/2015007

Dear Mr. Davison:

On September 4, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed a Component Design Bases Inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The purpose of this inspection was to verify that design bases have been correctly implemented for the selected risk-significant components, and that operating procedures and operator actions are consistent with design and licensing bases. The enclosed report documents the results of this inspection, which were discussed on September 4, 2015, with you, and other members of your staff.

This inspection examined activities conducted under your license as they relate to public health and safety to confirm compliance with the Commissions rules and regulations, and with the conditions in your license. Within these areas, the inspection consisted of a selected examination of procedures and representative records, field observations, and interviews with personnel.

Based on the results of this inspection, three NRC-identified findings of very low safety significance (Green) were identified. The issues were determined to involve violations of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your Corrective Action Program, the NRC is treating the issues as Non-Cited Violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy. These NCVs are described in the subject inspection report.

If you contest the subject or severity of the 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 III; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant.

In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 III; and the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," 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/

Christine A. Lipa, Chief Engineering Branch 2 Division of Reactor Safety Docket Nos. 50-282, 50-306 License Nos. DPR-42, DPR-60

Enclosure:

IR 05000282/2015007; 05000306/2015007

REGION III==

Docket Nos: 50-282; 50-306 License Nos: DPR-42; DPR-60 Report No: 05000282/2015007; 05000306/2015007 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: August 3, 2015, through September 4, 2015 Inspectors: J. Neurauter, Senior Reactor Inspector, Lead R. Walton, Senior Operations Engineer I. Hafeez, Reactor Inspector, Electrical G. ODwyer, Reactor Inspector, Mechanical C. Jackel, Reactor Inspector, NSPDP Observer J. Chiloyan, Electrical Contractor J. Zudans, Mechanical Contractor Approved by: Christine A. Lipa, Chief Engineering Branch 2 Division of Reactor Safety Enclosure

SUMMARY

Inspection Report 05000282/2015007, 05000306/2015007; 08/03/2015 - 09/04/2015; Prairie

Island Nuclear Generating Plant, Units 1 and 2; Component Design Bases Inspection.

The inspection was a 3-week on-site baseline inspection that focused on the design of components. The inspection was conducted by five regional engineering inspectors, and two consultants. Three Green findings were identified by the team. The findings were considered Non-Cited Violations (NCVs) of U.S. Nuclear Regulatory Commission (NRC)regulations. The significance of inspection findings is indicated by their color (i.e., Greater than Green, or Green, White, Yellow, Red), and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, dated April 29, 2015. Cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas effective date December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 201

Cornerstone: Mitigating System

Green.

The team identified a finding of very low safety significance, and an associated NCV of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion XI,

Test Control, for the licensees failure to have an acceptance criteria for electrical contact resistance values in preventive maintenance procedures for 4160 Vac switchgear. Specifically, the licensees preventive maintenance Procedure PE 0009, 4kV Switchgear Preventive Maintenance, failed to provide adequate resistance values and acceptance criteria for electrical connections at bus bar connection points and between 4kV switchgear cubicles. The licensee entered this finding into their Corrective Action Program (CAP) with a recommended action to add acceptance criteria into Table 1 of procedure PE 0009.

The performance deficiency was determined to be more than minor because it was associated with the procedural quality attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance because it was a design or qualification deficiency that did not represent a loss of operability or functionality. Specifically, the licensee determined the 4160 Vac switchgear cubicles were operable using guidance from Electric Power Research Institute Technical Report 1013457. The finding had a cross-cutting aspect associated with resources in the area of human performance. Specifically, the licensee management failed to ensure procedures are available to support successful work performance.

[H.1] (Section 1R21.3.b(1))

Green.

The team identified a finding of very low safety significance, and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to assure the safety-related thermal overload relay heaters were properly sized.

Specifically, the licensee failed to consider the effects of the higher acceptable stroke time limits specified in motor operated valve Surveillance Test Procedure SP 1137,

Recirculation Mode Valve Functional Test, in safety-related thermal overload sizing calculation H6.1, Motor Operated Valve Thermal Overload Heater Sizing for General Electric Motor Control Centers, Rev. 5. The licensee entered this finding into their CAP, and has actions in-place to stroke motor-operated valves to prevent a thermal overload relay trip.

The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of design control, and affected the cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events to prevent undesirable consequences. The finding screened as very low safety significance because the finding was a design deficiency confirmed not to result in a loss of safety function of a system or a train. Specifically, the licensee performed preliminary calculations and determined the thermal overload relays were operable. The team did not identify a cross-cutting aspect associated with this finding because it was confirmed not to be reflective of current performance due to the age of the performance deficiency. (Section 1R21.3.b(2))

Green.

The team identified a finding of very low safety significance, and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to design all components of the replacement Containment Fan Coil Units in accordance with Section III of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code. Specifically, the licensee failed to use Section III design rules to evaluate the Containment Fan Coil Unit header box as specified in the replacement Containment Fan Coil Unit design specification. The licensee entered this finding into their CAP with a recommended action to perform a condition evaluation for the new Containment Fan Coil Units to be installed in the upcoming refueling outage to ensure proper design code alignment with the design specification and the design report.

The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of design control, and affected the cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance because it was a design or qualification deficiency that did not represent a loss of operability or functionality. Specifically, the licensees use of design rules from American Society of Mechanical Engineers,Section VIII, provided reasonable assurance for the Containment Fan Coil Unit header box pressure boundary integrity. The team did not identify a cross-cutting aspect associated with this finding because it was confirmed not to be reflective of current performance due to the age of the performance deficiency. (Section 1R21.5.b(1))

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R21 Component Design Bases Inspection

.1 Introduction

The objective of the Component Design Bases Inspection is to verify that design bases have been correctly implemented for the selected risk-significant components, and that operating procedures and operator actions are consistent with design and licensing bases. As plants age, their design bases may be difficult to determine, and an important design feature may be altered or disabled during a modification. The Probabilistic Risk Assessment (PRA) model assumes the capability of safety systems and components to perform their intended safety function successfully. This inspectable area verifies aspects of the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones for which there are no indicators to measure performance.

Specific documents reviewed during the inspection are listed in the Attachment to this report.

.2 Inspection Sample Selection Process

The team used information from the licensees PRA and the U.S. Nuclear Regulatory Commissions (NRCs) Standardized Plant Analysis Risk Model to select a risk-significant accident scenario and risk-significant components. The scenario selected was a medium loss of coolant accident (LOCA). A number of risk-significant components that mitigate multiple accident scenarios, including those with Large Early Release Frequency (LERF) implications, were selected for the inspection.

The team also used additional component information such as a margin assessment in the selection process. This design margin assessment considered original design margin reductions caused by design modification, power uprates, or reductions due to degraded material condition. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as performance test results, significant corrective actions, repeated maintenance activities, Maintenance Rule (a)(1) status, components requiring an operability evaluation, NRC resident inspector input of problem areas/equipment, and system health reports. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins. A summary of the reviews performed and the specific inspection findings identified are included in the following sections of the report.

The team also identified procedures and modifications for review that were associated with the selected components. In addition, the team selected operating experience issues associated with the selected components.

This inspection constituted 20 samples (12 regular components, 2 components with LERF implications, and 6 operating experience) as defined in Inspection Procedure 71111.21-05.

.3 Component Design

a. Inspection Scope

The team reviewed the Updated Safety Analysis Report (USAR), Technical Specification (TS), design basis documents (DBDs), drawings, calculations and other available design basis information, to determine the performance requirements of the selected components. The team used applicable industry standards, such as the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, and Institute of Electrical and Electronics Engineers standards, to evaluate acceptability of the systems design. The NRC also evaluated licensee actions, if any, taken in response to NRC issued operating experience, such as Information Notices (INs).

The review verified that the selected components would function as designed when required and support proper operation of the associated systems. The attributes that were needed for a component to perform its required function included process medium, energy sources, control systems, operator actions, and heat removal. The attributes to verify that the component condition and tested capability were consistent with the design bases and appropriate may have included installed configuration, system operation, detailed design, system testing, equipment and environmental qualification, equipment protection, component inputs and outputs, operating experience, and component degradation.

For each of the components selected, the team reviewed the maintenance history, preventive maintenance (PM) activities, system health reports, operating experience-related information, vendor manuals, electrical and mechanical drawings, and licensee corrective action documents. Field walkdowns were conducted for all accessible components to assess material condition, including age-related degradation, and to verify that the as-built condition was consistent with the design. Other attributes reviewed are included as part of the scope for each individual component.

The following 14 components (samples) were reviewed:

• 4160 Volts Alternating Current (Vac) Switchgear Bus 16: The team reviewed nameplate data, design basis description and electrical calculations and drawings to confirm the bus design capability related to loading and short circuit protection and maintenance requirements were in conformance with applicable design standards. Test procedures and associated results were reviewed to verify bus components were adequately tested and degradation would be identified. The switchgear protective relay testing procedures and recently completed calibration test results were reviewed to verify that the acceptance criteria for tested parameters were supported by calculations or other controlled documents. The team performed independent calculations of available fault current contributions from the emergency diesel generator and from the offsite sources for postulated phase and ground faults and compared them with the relay settings calculations in Electrical Transient Analysis Program (ETAP) to verify the appropriateness of the applied overcurrent relay settings. The team also reviewed the 4 kilo-volt (kV) Bus 16 loss of voltage and bus overcurrent relay settings to ensure adequate coordination was maintained between the bus overcurrent and bus under voltage relay settings to ensure the overcurrent relays function as designed during postulated electrical bus faults. The team also reviewed the degraded voltage relay settings to verify whether they bounded the TS requirements. The team interviewed design and system engineers and operation personnel to determine whether there were any adverse operating trends or existing issues affecting buss reliability and to assess licensees ability to evaluate and correct problems. Field walkdown of 4kV switchgear bus 16 was performed to observe material condition and to verify whether breaker alignment, breaker position and status indications were consistent with plant design drawings.

• 4160 Vac Breaker 16-3 for 12 Motor-Driven Auxiliary Feedwater (MDAFW)

Pump: The team reviewed pump motor nameplate data, design basis description and electrical calculations and drawings to confirm the design basis minimum available voltage and current requirements for the 12 MDAFW pump motor were provided by the 4kV supply breaker. The phase and ground protective relay trip setpoints were reviewed to ensure adequate margin existed for pump motor protection and coordination to ensure no undue interference when the pump motor is performing its design function. The team also reviewed the motor feeder cable ampacity for overload and short circuit withstand capability. PM and relay calibration test records were reviewed to confirm the design basis assumptions in electrical calculations. The team performed independent calculations to determine whether the breaker overload and short circuit interrupting duty requirements were well within the breaker capacity. The team reviewed the 4kV Breaker 16-3 maintenance procedures and test records to verify that they conformed to industry standards and whether recorded contact parting times were within the design assumptions stated in licensees ETAP calculations and breaker vendor specifications. The team interviewed design and system engineers to determine whether there were any adverse operating trends or existing issues affecting 4kV Breaker 16-3 reliability and to assess licensees ability to evaluate and correct problems. Field walkdown of 4kV Breaker 16-3 was performed to observe material condition and to verify whether breaker alignment, breaker position and relay status indications were consistent with plant design drawings.

• 4160/480 Vac Transformer 121M: The team reviewed calculations, design basis descriptions, nameplate data and drawings to verify that the loading of Transformer 121M, the power supply breaker and the 480 Vac load was within the corresponding equipment ratings. The team reviewed design assumptions and calculations related to short circuit currents, voltage drop and protective relay settings associated with Transformer 121M to verify that they were appropriate.

The team reviewed a sample of completed maintenance and functional performance test results to verify that the power supply breaker associated with Transformer 121M and the power cables were capable of supplying the power requirements of the 480 Vac loads during normal and postulated accident conditions. The team interviewed system engineers to determine whether there were any adverse operating trends or existing issues affecting Transformer 121M reliability and to assess licensees ability to evaluate and correct problems. The team conducted field walkdown of the 4160/480 Vac Transformer 121M to verify that equipment alignment and nameplate data were consistent with design drawings and to assess the observable material condition.

• 480 Vac Distribution Bus 121: The team reviewed the 480 Vac Distribution Bus 121 to determine whether it was capable of performing its design basis function. The team reviewed associated DBDs and electrical distribution calculations including load flow, voltage drop, short-circuit, and electrical protection coordination. This review evaluated the adequacy and appropriateness of design assumptions, evaluated if bus capacity was exceeded and determined whether bus voltages remained above minimum acceptable values under design basis conditions. The team reviewed the trip setpoints of the overcurrent protective devices for Bus 121 supply and selected breakers at the load center to verify that the trip setpoints would not interfere with the ability of supplied equipment to perform their safety function yet ensuring the trip setpoints provided for adequate load center protection. Additionally, the team reviewed system maintenance test results, interviewed system engineers, and conducted field walkdowns to verify that equipment alignment, nameplate data, and breaker position were consistent with design drawings and to assess the material condition of the 480 Vac Distribution Bus 121 load center. Finally, the team reviewed corrective action documents and system health reports to determine whether there was any adverse operating trends and to assess licensees ability to evaluate and correct problems.

• 480 Vac Motor Control Center (MCC) 1A1: The team reviewed the 480 Vac MCC 1A1 to determine whether it was capable of performing its design basis function. The team reviewed the DBDs and electrical distribution calculations including load flow, voltage drop, short-circuit current, molded case circuit breaker application, thermal overload (TOL) relay heater sizing, and electrical protection coordination. This review evaluated the adequacy and appropriateness of design assumptions, evaluated whether the MCC 1A1 bus capacity was exceeded and determined whether bus voltages remained above minimum acceptable values under design basis conditions. The team reviewed the trip setpoints of the overcurrent protective devices including TOL relays to verify that the trip setpoints would not interfere with the ability of supplied equipment to perform their safety function yet ensuring the trip setpoints provided for adequate MCC protection. Finally, the team reviewed corrective action documents and system health reports to determine whether there was any adverse operating trends and to assess licensees ability to evaluate and correct problems. Additionally, the team reviewed system maintenance test results, interviewed system engineers, and conducted field walkdowns to verify that equipment alignment, nameplate data, and breaker positions were consistent with design drawings and to assess the material condition of the 480 Vac MCC 1A1.

• 125 Volts Direct Current (Vdc) Distribution Panel 15: The team reviewed the 125 Vdc Distribution Panel 15 to determine whether it was capable of performing its design basis function. The team reviewed the DBDs and electrical distribution calculations including load flow, voltage drop, short-circuit current, fused-disconnect applications, and electrical protection coordination. This review evaluated the adequacy and appropriateness of design assumptions, evaluated whether the 125 Vdc Distribution Panel 15 capacity was exceeded and determined whether bus voltages remained above minimum acceptable values under design basis conditions and met voltage and current requirements of connected safety-related 4160 Vac circuit breaker control and logic circuit loads.

The team reviewed licensees proposed plant modification design documents to verify whether the replacement of existing obsolete fused-disconnects had properly considered the original plant design basis requirements, including environmental and seismic, to preclude any potential adverse impacts on 125 Vdc Distribution Panel 15 capacity and all of its affected loads. Finally, the team reviewed corrective action documents and system health reports to determine whether there was any adverse operating trends and to assess licensees ability to evaluate and correct problems. Additionally, the team reviewed system maintenance test results, interviewed system engineers, and conducted field walkdowns to verify that equipment alignment, nameplate data, and fused-disconnect positions were consistent with design drawings and to assess the material condition of the125 Vdc Distribution Panel 15.

• 125 Vdc Distribution Panel 21: The team reviewed the 125 Vdc Distribution Panel 21 to determine whether it was capable of performing its design basis function. The team reviewed the DBDs and electrical distribution calculations including load flow, voltage drop, short-circuit current, fused-disconnect applications, and electrical protection coordination. This review evaluated the adequacy and appropriateness of design assumptions, evaluated whether the 125 Vdc Distribution Panel 21 capacity was exceeded and determined whether bus voltages remained above minimum acceptable values under design basis conditions and met voltage and current requirements of connected safety-related 4160 Vac circuit breaker control and logic circuit loads. The team reviewed licensees proposed plant modification design documents to verify whether the replacement of existing obsolete fused-disconnects had properly considered the original plant design basis requirements, including environmental and seismic, to preclude any potential adverse impacts on 125 Vdc Distribution Panel 21 capacity and all of its affected loads. Finally, the team reviewed corrective action documents and system health reports to determine whether there was any adverse operating trends and to assess licensees ability to evaluate and correct problems. Additionally, the team reviewed system maintenance test results, interviewed system engineers, and conducted field walkdowns to verify that equipment alignment, nameplate data, and fused-disconnect positions were consistent with design drawings and to assess the material condition of the125 Vdc Distribution Panel 21.

• 12 Component Cooling (CC) Pump: The team reviewed CC Water 12 CC pump to verify that it was capable of meeting its design basis requirements. The 12 CC pump provides intermediate cooling between heat exchangers in potentially radioactive systems and the cooling water system during normal operations and accident conditions. The team reviewed analyses, procedures, and test results associated with operation of the 12 CC pump under postulated transient, accident, and station blackout conditions. The analyses included considerations for hydraulic performance, net positive suction head, required total developed head, and pump run-out conditions. Seismic design documentation was reviewed to verify pump design was consistent with limiting seismic conditions.

The team also evaluated the chronic pump seal issues in the recent past as well as modifications to correct these problems. In-service testing (IST) results were reviewed to verify acceptance criteria were met and performance degradation would be identified, taking into account set-point tolerances and instrument inaccuracies. The team reviewed pump motor nameplate data, design basis description and electrical calculations and drawings to confirm the design basis minimum available voltage at the 12 CC pump motor terminals would be adequate for starting and running under degraded voltage conditions. The phase and ground protective relay trip setpoints were reviewed to ensure adequate margin existed for pump motor protection and coordination to ensure no undue interference when the pump motor is performing its design function. The team also reviewed the motor feeder cable ampacity for overload and short circuit withstand capability. A sample of PM and relay calibration test records were reviewed to confirm the design basis assumptions in electrical calculations.

The team performed independent calculations to determine if adequate time coordination margin existed between the 4kV bus undervoltage relays and the 12 CC pump motor supply feeder circuit overload current relay trip setpoints.

Field walkdown of the 12 CC pump motor power supply breaker in 4kV switchgear bus16, cubicle 5 was performed to observe material condition and to verify 12 CC pump motor power supply breaker alignment and status indications were consistent with plant design drawings. The team also conducted a detailed walkdown of the pump to assess the material and environmental conditions, and to verify that the installed configuration was consistent with system drawings, and the design and licensing bases. In addition, the team interviewed system, test and design engineers to discuss pump performance, trending and maintenance history to determine the overall condition of the pump. Finally, the team reviewed corrective action documents to evaluate whether there were any adverse trends associated with the pump and to assess the licensees capability to evaluate and correct problems.

• Unit 1 Reactor Coolant Pump (RCP) Seals: The team inspected the Unit 1 RCP seal replacement to determine if the new seal designs are acceptable and will perform their safety related function, as expected. During Prairie Island Nuclear Generating Plant refuel outage 1R29, the licensee replaced the existing Westinghouse seals with Flowserve N9000 seals. The replacement seals are of a different design than the original Westinghouse seals and required modifications to the seal leak-off lines, seal housing and pump coupling.

The Flowserve N-9000 seal provides a controlled leak barrier between the pressurized reactor coolant and the primary containment. The seal contains three hydrodynamic seal stages and a fourth abeyance seal, which provides sealing when the remaining three stages are failed. The team reviewed the USAR, TSs, TS Bases, drawings, procedures, modifications (EC 21790 and EC 25405), calculations, DBDs, the seal pressure breakdown operating trends, Reactor Coolant System makeup capability and root cause analyses associated with 12 RCP seal failures. The team also reviewed the seal maintenance history and health reports to assure that the system is being maintained at maximum levels considering open work orders (WOs) and legacy conditions and that plans for future maintenance can assure optimal system performance. The team verified that the seal design has operated as expected considering plant operating conditions as well as ongoing 12 RCP seal issues. Finally, the team reviewed corrective action documents to evaluate whether the adverse trends associated with the 12 RCP seal were acceptably managed to verify that the licensee evaluated and corrected problems effectively.

• 12 Residual Heat Removal (RHR) Pump: The team reviewed pump motor nameplate data, design basis description, electrical calculations, and drawings to confirm the design basis minimum available voltage at the 12 RHR pump motor terminals would be adequate for starting and running under degraded voltage conditions. The phase and ground protective relay trip setpoints were reviewed to ensure adequate margin existed for pump motor protection and coordination to ensure no undue interference when the pump motor is performing its design function. The team also reviewed the motor feeder cable ampacity for overload and short circuit withstand capability. PM and relay calibration test records were reviewed to confirm the design basis assumptions in electrical calculations. The team performed independent calculations to determine if adequate time-current coordination margin existed between the 4kV bus undervoltage relays and the 12 RHR motor supply feeder circuit overload current relay trip setpoints. Field walkdown of 4kV RHR pump motor power supply breaker in 4kV swithchgear bus 16 cubicle 6 was performed to observe material condition and to verify 12 RHR pump motor power supply breaker alignment and status indications were consistent with plant design drawings.

• Containment Sump B Isolation Valves MV-32076 and MV-32078: The team reviewed the Unit 1 containment sump isolation valves, MV-32076 (inboard containment isolation valve) and MV-32078 (outboard containment isolation valve), to determine if the normally closed valves in the B RHR sump are capable of performing their design basis function to open while transferring to the recirculation mode of safety injection. The team reviewed the USAR, TSs, TS Bases, drawings, procedures, and the IST basis document to identify the performance requirements for the valves. The team reviewed periodic motor-operated valve (MOV) diagnostic test results and stroke-timing test data to verify acceptance criteria were met. The team evaluated whether the MOV safety functions, performance capability, torque switch configuration, and design margins were adequately monitored and maintained in accordance with the licensees MOV program requirements. The team also reviewed MOV weak link calculations to ensure the ability of the MOV to remain structurally functional while stroking under design basis operating conditions. The team verified that the MOV valve analysis used the maximum differential pressure expected across the valve during worst case operating conditions. Additionally, the team reviewed motor nameplate data, degraded voltage and during the most limiting duty cycle operating conditions, TOL relay sizing, and voltage drop calculation results to verify that the MOV would have sufficient voltage and power available to perform its function at degraded voltage and during the most limiting duty cycle operating conditions. The design, operation, and maintenance of the valve were discussed with the system engineer to evaluate the valves performance history, maintenance, and overall health. The function and design of the valve enclosures were reviewed for the primary containment function and capability. The team also conducted a walkdown of the valves and associated equipment to assess the material condition of the equipment and to evaluate whether the installed configuration was consistent with the plant drawings, procedures, and the design bases. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were any adverse trends associated with the valves and to assess the licensees capability to evaluate and correct problems.

• 12 MDAFW Pump: The team reviewed design calculations and site procedures to verify the design bases and design assumptions were appropriately translated into these documents. Design and operational requirements were reviewed with respect to electric supply, pump flow rate, developed head, achieved system flow rate, net positive suction head and minimum flow requirements. The team reviewed the adequacy of assumptions, limiting parameters, the pumps protection from the formation of air vortexes, and the adequacy of its suction sources (condensate storage tank and safety-related cooling water discharge piping). Test procedures and recent test results were reviewed against design basis documents to verify the acceptance criteria for tested parameters were supported by calculations or other engineering documents and validated component operation under accidents and transients. This included reviewing the adequacy of pump IST. The team also reviewed operating as well as emergency operating procedures to verify selected operator actions could be accomplished.

• Unit 1 Condensate Storage Tank (CST) (LERF Implications): The team reviewed the design basis of the tanks to verify their capability to supply the required inventory to the Auxiliary Feedwater (AFW) system during postulated transient and accident conditions. The CST level setpoint analyses were reviewed to verify the transfer of the AFW system suction from the CSTs to the safety-related Cooling Water System would occur prior to significant vortexing, which could result in air reaching the pump suction nozzle. The team also reviewed the operator actions required to maintain the tanks above the minimum allowable level and temperature limits

• Safety Injection Check Valves CV 9-5 and CV 9-6 (LERF Implications):

The team reviewed the Unit 1 Safety Injection valves CV 9-5 and CV 9-6, to determine if the normally closed pressure isolation check valves in the safety injection system are capable of performing their design basis function to isolate the RHR system (Low Pressure) from the Reactor Coolant System (High Pressure), and to open to provide a flow path for low head safety injection and long term low head recirculation. The team reviewed the USAR, TSs, TS Bases, drawings, procedures, modifications, calculations, DBDs and the IST basis document to identify the performance requirements for the valves. The team reviewed periodic check valve diagnostic test results to verify acceptance criteria for leakage and full flow capability were met. The team evaluated whether the check valve safety functions, performance capability, were adequately monitored and maintained in accordance with Prairie Islands IST Program requirements.

The team also reviewed the valve maintenance history and health reports to assure that the system is being maintained at maximum levels considering aggregate effects of open WOs and legacy conditions and that plans for future maintenance can assure optimal system performance. The team verified that the check valves pressure isolation function at the maximum differential pressure expected across the valves during worst case operating conditions are being maintained.

b. Findings

(1) 4160 Vac Switchgear PM Procedure Failed to Provide Adequate Resistance Values and Acceptance Criteria

Introduction:

A finding of very low safety significance, and an associated Non-Cited Violation (NCV) of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion XI, Test Control, was identified by the team for the licensees failure to have an acceptance criteria for electrical contact resistance values in PM procedures for 4160 Vac switchgear. Specifically, the licensees PM Procedure PE 0009, 4kV Switchgear PM, failed to provide adequate resistance values and acceptance criteria for electrical connections at bus bar connection points and between 4kV switchgear cubicles.

Description:

The team reviewed the last PM procedures for the safety-related 4160 Vac switchgear and the results for WO 00359703-1, Bus 16 Inspection/DOBLE last performed in July 2012. The tests were performed in accordance with Procedure PE 0009, 4kV Switchgear PM, Revision 21. Procedure Step 7.5.5, Measure Contact Resistance, measured the resistance from cubicle-to-cubicle and end-to-end on bus stab of the cubicle for each phase when Bus Grounds are installed (i.e., the bus is grounded). The test values and location of the tests varied depending on the live cubicle position and testing configuration.

A note prior to Procedure Step 7.5.5 states: Typical resistance between adjacent cubicles is less than 75 micro-ohms. Discussions with the licensee identified that this note provided general guidance and does not provide firm acceptance criteria for cubicle-to-cubicle, end of bus to end of bus, or situations when cubicles are bypassed due to being energized. In accordance with procedure Step 7.5.8, if the contact resistance and the power factor are within limits, then the steps in procedure Section 7.10 may be identified as non-applicable with the system engineers or maintenance supervisors approval. However, the team noted that the WO and associated procedure PE 0009 did not have any proper acceptance criteria provided in the procedure and requested the licensee to provide the basis of the contact resistance acceptance criterion used in maintenance testing. However, the licensee could not provide a basis for the contact resistance value used in maintenance testing.

The licensee provided the team a non-controlled spread sheet with historical contact resistance readings and Electric Power Research Institute (EPRI) Technical Report 1013457,Nuclear Maintenance Applications Center: Switchgear and Bus Maintenance Guide. Section 6.7.1 of this EPRI report is associated with testing connection resistance and states, in-part:

• "Connection resistance or the measure of resistivity associated with a connection point provides an indication of the adequacy of the connection. Higher resistance can lead to overheating and subsequent failure of the insulation and electrical conductor. The physical configuration of the bus, including the number of connections, can influence readings due to the cumulative resistance values at each joint. Cumulative resistance values can be used for large bus sections with multiple connections considering individual joint resistance values. Baseline values can be established and trended with future measurements to provide assurance of the adequacy of each connection. This can establish a systematic approach to identify deviations or outliers. An acceptance criteria could include a method to investigate values that deviate more than 50 percent from the lowest value."

However, the licensee could not demonstrate the EPRI guidance using the 50 percent deviation from the lowest value method criteria was incorporated into licensee procedures. Therefore, the team concluded the WO and associated procedure PE 0009 did not provide proper acceptance criteria.

The team concluded that without a basis for the testing acceptance criteria, the licensee cannot demonstrate the 4160 Vac switchgear bus will perform satisfactorily in service.

The licensee entered this finding into their Corrective Action Program (CAP) as Action Request (AR) 01490563, and its preliminary evaluation concluded 4kV switchgear cubicles were operable using the EPRI Technical Report 1013457 guidance; the licensee recommended adding acceptance criteria into Table 1 of procedure PE 0009.

Analysis:

The team determined that the failure to have an acceptance criteria for electrical contact resistance values in safety-related preventive maintenance procedures was contrary to 10 CFR Part 50, Appendix B, Criterion XI and was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to establish contact resistance acceptance criteria was a significant programmatic deficiency which would have the potential for unacceptable or degraded conditions to go undetected.

The team determined the finding could be evaluated in accordance with Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions. The finding screened as very low safety significance (Green) because it did not result in the loss of operability or functionality. Specifically, the licensee determined 4kV switchgear cubicles were operable using Technical Report 1013457 guidance.

The team determined that this finding had a cross-cutting aspect associated with resources in the area of human performance. Specifically, the licensee management failed to ensure procedures are available to support successful work performance. [H.1]

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service and performed in accordance with written test procedures which incorporate the requirements and acceptance limits.

Contrary to the above, as of September 4, 2015, the licensee failed to provide adequate resistance values and acceptance criteria for electrical connections at bus bar connection points and between 4kV switchgear cubicles in Procedure PE 0009 used for PM testing of 4160 Vac switchgear.

Because this violation was of very low safety significance, and was entered into the licensees CAP as AR 01490563, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. ( NCV 05000282/2015007-01; 05000306/2015007-01, 4160 Vac Switchgear PM Procedure Failed to Provide Adequate Resistance Values and Acceptance Criteria)

(2) Inadequate Calculations for MOV TOL Relays

Introduction:

The team identified a finding of very low safety significance, and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control.

Specifically, the licensee failed to assure and verify that the TOL relays on safety-related MOV circuits were properly sized.

Description:

During review of 480 volt power supply circuits for MV-32076 and MV-32078, the team noted that TOL relay evaluation Form PINGP 1111, MOLR Heater Sizing, Rev. 5, had assumed valve stroke times of 120 and 118 seconds, respectively.

However, the team noted the licensee had not considered the effects of the longer 150 second allowable stroke time identified as the Limiting Stroke Time in Surveillance Procedure SP 1137, Recirculation Mode Valve Functional Test, Rev. 31. The team questioned whether the non-conservative assumed stroke time used in TOL relay sizing calculations combined with licensees design that leave the TOL relays in the MOV circuits continuously could result in undersized TOL relays that could trip on overcurrent and de-energize the MOV motor circuits during a design basis event and prevent the safety-related MOVs from performing their safety-related function. The team reviewed licensees TOL sizing procedure H6.1, MOV TOL Heater Sizing for General Electric (GE) MCCs, Rev. 5, and determined the calculation failed to consider the most limiting valve stroke time and failed to demonstrate by calculation or analysis that the TOL protection was sized properly. The team identified that, as of September 29, 2009, the licensee had no program to ensure MOV Limiting Stroke Time and Duty Cycle parameters were identified and verified as required design inputs into the TOL sizing calculations to ensure functional reliability and accuracy of the selected TOL trip points provide adequate MOV motor circuit overcurrent protection and coordination margin to preclude spurious tripping during all design basis MOV operation.

The licensee entered this issue into their CAP as AR 01490676. The licensee is still evaluating its planned corrective actions. However, the team determined that the continued non-compliance does not present an immediate safety concern because the licensee has actions in-place to stroke the MOVs to prevent a TOL relay trip. Therefore, the licensee was able to demonstrate operability in that the TOL protection would not prevent any MOVs from performing their safety function.

Analysis:

The team determined that failing to assure that TOL protection on safety-related MOV circuits was sized properly and verified was a performance deficiency warranting a significance evaluation. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to assure that TOL protection was properly sized could affect the ability of MOVs to respond to initiating events.

The team determined the finding could be evaluated in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions. The finding screened as very low safety significance (Green) because it did not result in the loss of operability or functionality. Specifically, the licensee was able to demonstrate operability in that the TOL protection would not prevent any MOVs from performing their safety function and has corrective actions in-place to stroke certain MOVs non-consecutively to prevent a TOL relay trip.

The team did not identify a cross-cutting aspect associated with this finding because the finding was not representative of current performance. Specifically, the finding was related to original plant design.

Enforcement:

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

Contrary to the above, as of September 29, 2009, the licensee failed to ensure design control measures were in place for verifying or checking the adequacy of the design of the TOL relays for the safety-related MOVs, MV-320076, 11 Containment Sump B Isolation Valve A2, and MV-32078, 11 Containment Sump B Isolation Valve B2, powered from 480 volt MCCs 1KA2-B1 and 1A2-A5, respectively.

Because this violation was of very low safety significance, and was entered into the licensees CAP as AR 01490676, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000282/2015007-02; 05000306/2015007-02, Inadequate Calculations for MOV TOL Relays)

.4 Operating Experience

a. Inspection Scope

The team reviewed six operating experience issues (samples) to ensure that NRC generic concerns had been adequately evaluated and addressed by the licensee.

The operating experience issues listed below were reviewed as part of this inspection:

• Generic Letter (GL) 96-06 Assurance of Equipment Operability and containment Integrity During Design-Basis Accident Condition;

• Institute of Nuclear Power Operations (INPO) Event Report (IER) L2-14-46, Multiple Electrical Faults Result in Explosion of Unit Auxiliary Transformer and Automatic Scram;

• IER L3-13-04, RCP Motor Bearing Damage ;

• IER L3-14-25 Heavy Snow and Design Flaw Result in Dual Unit Scram;

• IN 2012-14, MOV Inoperable Due to Stem-Disk Separation; and

• IN 2014-10, Potential Circuit Failure-Induced Secondary Fires or Equipment Damage.

b. Findings

No findings were identified.

.5 Modifications

a. Inspection Scope

The team reviewed seven permanent plant modifications related to selected risk-significant components to verify that the design bases, licensing bases, and performance capability of the components had not been degraded through modifications.

The modifications listed below were reviewed as part of this inspection effort:

• Engineering Change (EC) 23725, Direct Current Panel 21 Fused Switch Replacement;

• EC 18153, Replacement of Battery Chargers 21 and 22 and Portable Battery Charger 11P;

• EC 21790, RCP Seal Replacements Unit 1;

• EC 25405, Prairie Island 12 RCP Seal Face Replacement;

• EC 23833, 12 CC Pump Seal Face Material Equivalency Evaluation;

• Modification 05ZC02; Unit 2 Fan Coil Unit Cooling Faces Replacement; and

• Modification 05ZC05; Unit 1 Containment Fan Coil Unit Cooling Faces Replacement.

b. Findings

(1) Replacement Containment Fan Coil Unit (CFCU) Component Not Designed in Accordance with ASME Section III

Introduction:

The team identified a finding of very low safety significance, and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to design all components of the replacement CFCUs in accordance with ASME Section III. Specifically, the licensee failed to use ASME Section III design rules to evaluate the CFCU header box as specified in the replacement CFCU Design Specification.

Description:

Section 5.2.3.3 of the USAR describes the Containment Vessel Air Handling System including the CFCUs. This section states, in-part, the Containment Cooling System consists of four fan-coil units located in the Reactor Containment Vessel. These will re-circulate and cool the Reactor Containment Vessel atmosphere.

The heat sink for the fan coils is provided by the containment and auxiliary building Chilled Water System or by the Cooling Water System. During emergency situations, the heat sink for the fan coils is provided by the Cooling Water System.

The CFCUs are safety related and required to be operable in modes 1 - 4 by TS 3.6.5, Containment Spray and Cooling Systems. Along with the Containment Spray System, the Containment Cooling System limits the temperature and pressure that could be experienced following LOCA or steam line break.

As a result of flow induced erosion causing pressure boundary leaks, the licensee initiated modifications to replace existing fan coil unit (FCU) cooing coils. The team reviewed modification documentation that supported CFCU replacement to verify the modifications maintained design and licensing bases with respect to the licensees response to GL 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions. In particular, the team reviewed a sample of design documents to verify CFCU internal pressure transients due to design basis accidents postulated in GL 96-06 were considered as a design load.

As indicated in Modifications 05ZC05, Unit 1, and 05ZC02, Unit 2, the licensee specified the replacement FCU cooling faces to be designed and fabricated in accordance with ASME Section III, Class 2, 1989 Edition (no Addenda). The licensee noted that the use of ASME Section III was consistent with the original Specification TS-M605. The modifications utilized the original specification, USAR loading requirements, GL 96-06 water hammer loads, and transient pressure loading due to two-phase flow collapse. The licensee incorporated these requirements into Design Specification M180 0001 009, Unit 1, and Design Specification M180 0001 008, Unit 2, for CFCU face replacement. The team determined that the licensee reconciled using ASME Section III, Class 2, 1989 Edition as the replacement CFCU design code in ASME Section XI repair/replacement plan documents and in modification document 05ZC05, Unit 1, and in modification document 05ZC02, Unit 2.

The team reviewed a sample of design documents to verify the design requirements were incorporated into the design specification and the replacement CFCUs were designed and fabricated in accordance with the design specifications. The team verified that the design loads included USAR loading requirements, GL 96-06 water hammer loads, and transient pressure loading due to two-phase flow collapse.

However, the team determined that the CFCU header box component was evaluated using rules from Appendix 13 of ASME Section VIII, Div. 1, Rules for Construction of Pressure Vessels, instead of ASME Section III, Subsection NC, Class 2, as specified in the design specifications. Specifically, Section 4 of licensee Design Specification M180 0001 008 specifies the coils shall be designed in accordance with ASME Section III, Class 2. In addition, Section 4.4 of this design specification utilized Tables NC-3321-1 and NC-3321-2 for load combinations, service levels, and allowable stress levels for design of nozzles and nozzle connections to the header boxes.

The team identified Sub-Article NC-3200 contains design rules for vessels which may be used as an alternative to the vessel design rules in NC-3300 to evaluate the CFCU header box component. Specifically, NC-3211-1(c) allows the designer to perform a complete stress analysis of the vessel or vessel region considering all the loadings of NC-3212 and the Design Specifications. This analysis shall be done in accordance with Section III, Appendix XIII for all applicable stress categories. The team did not identify referral in Section III, Class 2 to ASME Section VIII for alternative vessel design rules.

Therefore, the team could not conclude the design reports for Aerofin Calculation CA-529-1158, Unit 1, and Calculation CA-529-1121-1, Unit 2, demonstrated replacement CFCUs were designed using the rules of ASME Section III, Class 2 in accordance with the design specifications.

The licensee captured this issue in their CAP as AR 0140769. The corrective action recommended at the time of this inspection was for the licensee to perform a condition evaluation for the new CFCUs to be installed in the upcoming refueling outage to ensure proper design code alignment with the design specification and the design report.

Analysis:

The team determined that the licensees failure to use the design rules of ASME Section III to evaluate the replacement CFCU header box component was contrary to the replacement CFCU design specification and was a performance deficiency. Specifically, the team determined that ASME Section III, NC-3200 contains design rules for vessels which may be used as an alternative to the vessel design rules in NC-3300 to evaluate the CFCU header box component.

The performance deficiency was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of Design Control, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the licensee did not perform a code reconciliation to demonstrate ASME Section VIII design rules are comparable to a complete stress analysis of the header box component in accordance with alternative vessel design rules specified in ASME Section III, Sub-Article NC-3200.

The team determined the finding could be evaluated in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions. The finding screened as very low safety significance (Green) because it did not result in the loss of operability or functionality. Specifically, the finding is a deficiency affecting the design qualification.

The team determined that meeting the design rules of ASME Section VIII provided reasonable assurance for CFCU header box pressure boundary integrity.

The team did not identify a cross-cutting aspect associated with this finding because it was confirmed not to be reflective of current performance due to the age of the performance deficiency.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures and instructions. These measures shall include provisions to assure that appropriate quality standards are specified and that deviations from such standards are controlled.

Contrary to the above, since 2005, the licensee failed to assure that the appropriate design standard was used to evaluate the replacement CFCU header box component.

Specifically, the licensee failed to use ASME Section III design rules as specified in the replacement CFCU design specification.

Because this violation was of very low safety significance and was entered into the licensees CAP as AR 01490769, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000282/2015007-03; 05000306/2015007-03, Replacement CFCU Component Not Designed in Accordance with ASME Section III)

.6 Operating Procedure Accident Scenarios

a. Inspection Scope

The team performed detailed review of risk-significant, time critical operator actions (TCOAs). These actions were selected from the licensees PRA rankings of human action importance based on risk-achievement worth values and selected scenarios of small/medium break LOCAs. The team reviewed licensee procedures and performed plant walkdowns. The team observed the licensee administer simulator scenarios and an in-plant job performance measure (JPM) to determine whether operators were implementing the procedure steps in a timely and accurate manner and to verify the procedures were appropriate to sufficiently mitigate events. The procedures were compared to USAR and risk assumptions. In addition, the procedures were reviewed to ensure the procedure steps would accomplish the desired result.

The following TCOAs were demonstrated, timed and reviewed against operating procedures and design documents:

• JPM: Secure Turbine Building Roof Exhaust Fans Following a LOCA, TCOA 8;

• Scenario: Complete Safety Injection Pump Recirculation Switchover, TCOA 24; and

• Scenario: Trip RCPs Following a Small Break LOCA, TCOA 25.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered Into the Corrective Action Program

a. Inspection Scope

The team reviewed a sample of the selected component problems identified by the licensee, and entered into the CAP. The team reviewed these issues to verify an appropriate threshold for identifying issues, and to evaluate the effectiveness of corrective actions related to design issues. In addition, corrective action documents written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problem into the CAP. The specific corrective action documents sampled and reviewed by the team are listed in the attachment to this report.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On September 4, 2015, the team presented the inspection results to Mr. K. Davison, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The team asked the licensee whether any materials examined during the inspection should be considered proprietary. Several documents reviewed by the team were considered proprietary information and were either returned to the licensee or handled in accordance with NRC policy on proprietary information.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Davison, Site Vice President

S. Sharp, Director of Site Operations

E. Blondin, Director of Engineering

M. Molaei, Director of Nuclear Engineering

T. LaHann, Acting Design Manager

M. Pearson, Regulatory Affairs Manager

J. Connors, Fleet Design Engineering Supervisor

K. Hernandez, Engineering Supervisor

G. Carlson, Senior Licensing Engineer

P. Johnson, Regulatory Affairs

U.S. Nuclear Regulatory Commission

K. Riemer, Chief, Projects Branch 3, DRP

L. Haeg, Senior Resident Inspector

P. LaFlamme, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

4160 Vac Switchgear Preventive Maintenance

05000282/2015007-01; NCV Procedure Failed to Provide Adequate Resistance

05000306/2015007-01 Values and Acceptance Criteria (Section 1R21.3.b(1))

05000282/2015007-02; Inadequate Calculations for Motor-Operated Valve NCV

05000306/2015007-02 Thermal Overload Relays (Section 1R21.3.b(2))

Replacement Containment Fan Cooling Unit

05000282/2015007-03; NCV Component Not Designed in Accordance with ASME

05000306/2015007-03 Section III (Section 1R21.5.b(1))

Discussed

None