IR 05000254/2014008

IR 05000254/2014008, 05000265/2014008; on 11/03/2014 - 12/05/2014; Quad Cities Nuclear Power Station, Units 1 and 2; Component Design Bases Inspection (CDBI)

ML15016A254
Person / Time
Site:	Quad Cities
Issue date:	01/15/2015
From:	Ann Marie Stone NRC/RGN-III/DRS/EB2
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
Andrew Dunlop
References
IR-2014008
Download: ML15016A254 (32)

Text

UNITED STATES ary 15, 2015

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2, COMPONENT DESIGN BASES INSPECTION 05000254/2014008; 05000265/2014008

Dear Mr. Pacilio:

On December 5, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed a Component Design Bases Inspection (CDBI) at your Quad Cities Nuclear Power Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on December 5, 2014, with Mr. S. Darin, and other members of your staff.

Based on the results of this inspection, one NRC-identified finding of very low safety significance was identified. The finding involved a violation of NRC requirements. However, because of its very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating the issue as a Non-Cited Violation (NCV) in accordance with Section 2.3.2 of the NRC Enforcement Policy If you contest the subject or severity of this NCV, 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 a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Quad Cities Nuclear Power Station. 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 Quad Cities Nuclear Power Station. 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/

Ann Marie Stone, Chief Engineering Branch 2 Division of Reactor Safety Docket Nos. 50-254; 50-265 License Nos. DPR-29; DPR-30

Enclosure:

Inspection Report 05000254/2014008; 05000265/2014008 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-254; 50-265 License Nos: DPR-29, DPR-30 Report No: 05000254/2014008; 05000265/2014008 Licensee: Exelon Generation Company, LLC Facility: Quad Cities Nuclear Power Station, Units 1 and 2 Location: Cordova, IL Dates: November 3 - 7, 2014; November 17 - 21, 2014; and December 1 - 5, 2014 Inspectors: A. Dunlop, Senior Engineering Inspector, Lead B. Jose, Senior Engineering Inspector, Electrical G. ODwyer, Engineering Inspector, Mechanical R. Walton, Operations Inspector S. Kobylarz, Electrical Contractor C. Baron, Mechanical Contractor Observer: M. Jeffers, Engineering Inspector, Electrical Approved by: Ann Marie Stone, Chief Engineering Branch 2 Division of Reactor Safety Enclosure

SUMMARY

Inspection Report 05000254/2014008, 05000265/2014008; 11/03/2014 - 12/05/2014; Quad

Cities Nuclear Power Station, Units 1 and 2; Component Design Bases Inspection (CDBI).

The inspection was a 3-week onsite baseline inspection that focused on the design of components. The inspection was conducted by regional engineering inspectors and two consultants. One Green finding was identified by the inspectors. The finding was considered a Non-Cited Violation (NCV) of 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 IMC 0609, Significance Determination Process dated June 2, 2011. 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 2014.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to effectively identify, evaluate, and document aging effects on plant equipment and structures as part of the licensees Aging Management Programs for a plant within its period of extended operation. The inspectors identified two corroded pipe supports and associated base plates in the Unit 1 high pressure coolant injection (HPCI) room as well as a severely corroded nut and stud on the 1/2 diesel generator cooling water pump outboard mechanical seal. These conditions had not been previously identified, evaluated, or documented. The licensee entered this finding into their Corrective Action Program.

The performance deficiency was determined to be more than minor and a finding in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. The finding screened as very low safety significance (Green) because the inspectors were able to answer No to each screening question, because the conditions had not yet affected structural integrity or operability of the systems. Specifically, the licensee confirmed the HPCI supports would be capable to perform their function and the remaining bolts on the mechanical seal were sufficient to prevent excessive leakage. The inspectors identified a cross-cutting aspect associated with this finding in the area of Human Performance, Resources component, because the licensee did not ensure that personnel, equipment, procedures, and other resources are adequate to assure nuclear safety by maintaining long term plant safety. [H.1] (Section 1R21.3.b.(1))

Licensee-Identified Violations

No violations were identified.

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 the report.

.2 Inspection Sample Selection Process

The inspectors used information contained in the licensees PRA and the Quad Cities Nuclear Power Station, Units 1 and 2, Standardized Plant Analysis Risk Model to identify a scenario to use as the basis for component selection. The scenario selected was an Anticipated Transient without Scram (ATWS). Based on this scenario, a number of risk significant components, including those with Large Early Release Frequency (LERF)implications, were selected for the inspection.

The inspectors also used additional component information such as a margin assessment in the selection process. This design margin assessment considered original design 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 inspectors also identified procedures and modifications for review that were associated with the selected components. In addition, the inspectors selected operating experience issues associated with the selected components.

This inspection constituted 17 samples as defined in Inspection Procedure 71111.21-05.

[12 Non-LERF components, 2 LERF components, and 3 operating experience]

.3 Component Design

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), Technical Specifications (TS), design basis documents, drawings, calculations and other available design basis information, to determine the performance requirements of the selected components. The inspectors used applicable industry standards, such as the American Society of Mechanical Engineers (ASME) Code, Institute of Electrical and Electronics Engineers (IEEE) Standards, and the National Electric Code, 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 Bulletins, Generic Letters (GLs),

Regulatory Issue Summaries (RISs), and Information Notices (INs). The review was to verify 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 was consistent with the design bases and was appropriate may include 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 inspectors reviewed the maintenance history, preventive maintenance activities, system health reports, operating experience-related information, vendor manuals, electrical and mechanical drawings, and licensee Corrective Action Program 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, including 2 with LERF implications, were reviewed:

• High Pressure Coolant Injection (HPCI) Pump/Turbine Driver (1-2302/1-2303):

The inspectors reviewed the design basis of the pump and turbine driver including performance requirements, net positive suction head (NPSH)requirements, and temperature limits. The inspectors reviewed normal, test, and emergency procedures as well as the potential for system water hammer during pump shutdown. The inspectors reviewed the function of the HPCI pump during a postulated ATWS event. The inspectors reviewed surveillance test procedures and recent test results to verify acceptance criteria were met and performance degradation would be identified.

• Contaminated Condensate Storage Tanks (CCSTs) (0-3303A/B): The inspectors reviewed the design basis of the tanks to verify their capability to supply the required inventory to the HPCI and reactor core isolation cooling systems during postulated transient and accident conditions. The CCST level setpoint analyses were reviewed to verify the transfer from the CCSTs to the torus would automatically occur prior to significant vortexing, which could result in air reaching the pump suctions. The inspectors reviewed the operator actions required to maintain the tanks above the minimum allowable temperature limit.

The inspectors also reviewed the criteria for transferring the HPCI pump suction from the torus to the CCST during a postulated ATWS event.

• HPCI Turbine Exhaust Check Valve (1-2301-45): The inspectors reviewed the design basis of the check valve, located in the steam exhaust line from the HPCI pump turbine driver. The inspectors reviewed normal, test, and emergency procedures associated with HPCI system operation. The inspectors also reviewed the pressure drop analysis prepared for the replacement check valve.

• HPCI Minimum Flow Valve (1-2301-14): The inspectors reviewed the motor-operated valve (MOV) calculations, including required thrust, weak link, and maximum differential pressure, to ensure the valve was capable of functioning under design and licensing bases conditions. Diagnostic and Inservice test (IST)results were reviewed to verify acceptance criteria were met and performance degradation would be identified. The inspectors reviewed the control logic and opening/closing setpoints to ensure the valve functions as designed to meet HPCI system requirements.

• Safety Relief Valve (1-0203-3A): The inspectors reviewed the design basis of the air-operated safety relief valve (SRV) including requirements for the valve to operate under postulated transient and accident conditions. This review included the capacity of the safety-related pneumatic supply system to open the valve under the most limiting conditions. The inspectors reviewed surveillance test procedures as well as the results of recent tests to verify acceptance criteria were met and performance degradation would be identified. The inspectors also reviewed the capability of the valve to operate multiple times under the most limiting temperature and pressure conditions. The inspectors reviewed elementary diagrams to confirm that the SRV solenoid valve operation conformed to the design requirements. The inspectors reviewed 125Vdc voltage drop analysis to confirm that the SRV solenoid valve received adequate voltage to operate during the most limiting battery conditions, during normal and accident environmental conditions, and for the most limiting operating service conditions.

The inspectors confirmed that the cabling to the solenoid valve was adequately sized. The inspectors also reviewed preventive maintenance performed to confirm that the solenoid coils were installed and maintained as required by the equipment qualification.

• Main Steam Isolation Valve (1-202-001A): The inspectors reviewed the design basis of the main steam isolation valve (MSIV), the basis for its closure time requirements, and the associated control logic. The inspectors reviewed normal, test, and emergency procedures. The inspectors reviewed air accumulator leakage limits, leak test procedures, and recent results to verify acceptance criteria were met and performance degradation would be identified. The inspectors reviewed closure time surveillance procedures and recent results to verify that the test results were representative of the most limiting postulated accident conditions. The inspectors reviewed the testing of the control circuits required to close the MSIVs to ensure that the testing was comprehensive and the valves would close as required in the event of a single failure of the control circuit. The inspectors also reviewed photographs of the valve to verify its material condition. The inspectors reviewed elementary diagrams to confirm that the SRV solenoid valve operation conformed to the design requirements. The inspectors reviewed the testing performed for the primary containment isolation system logic to confirm proper operation for the control circuit that removed power from the solenoid valve(s). The inspectors also reviewed preventive maintenance performed to confirm that the solenoid coils were installed and maintained as required by the equipment qualification.

• Reserve Auxiliary Transformer 12 (T12): The inspectors reviewed one-line diagram and protective relaying schematic diagrams to determine the overcurrent protection requirements. The inspectors reviewed the load flow analysis, the short circuit current calculation, and the coordination calculation to confirm proper coordination for transformer protection and the downstream bus incoming circuit breakers. The breaker calibration test results were reviewed to confirm the main incoming bus breaker settings were in conformance with the coordination analysis. The inspectors also verified the preventive maintenance performed on the transformer and transformer auxiliaries was in accordance with vendor recommendations.

• Turbine Building 125Vdc Main Bus 1A: The inspectors reviewed 125Vdc short circuit calculations and verified the interrupting ratings of the fuses and the molded-case circuit breakers were well above the calculated short circuit currents. The 125Vdc voltage drop calculations were reviewed to determine if adequate voltage would be available for the breakers open and close coils and spring charging motors. The inspectors reviewed the motor control logic diagrams and the 125Vdc voltage drop calculation to ensure adequate voltage would be available for the control circuit components under all design basis conditions. The inspectors also reviewed the 125Vdc short circuit and coordination calculations to assure coordination between the motor feed breaker open and close control circuit fuses, and 125Vdc supply breakers and to verify the interrupting ratings of the control circuit fuses and the 125Vdc control power feed breaker.

• Reactor Building 125Vdc Distribution Panel 1: The inspectors reviewed 125Vdc short circuit calculations and verified the interrupting ratings of the fuses and the molded-case circuit breakers were well above the calculated short circuit currents. The 125Vdc voltage calculations were reviewed to determine if adequate voltage would be available for the 4 kV breaker control components.

The inspectors reviewed the panel feeder and branch circuit power cable sizes and ampacities and verified those cables are adequately sized. The inspectors also reviewed the 125Vdc short circuit and coordination calculations to assure coordination between the motor feed breaker open and close control circuit fuses, and 125Vdc supply breakers and to verify the interrupting ratings of the control circuit fuses and the 125Vdc control power feed breaker.

• 4160Vac Essential Switchgear Bus 13-1: The inspectors reviewed vendor specifications, name plate data, one-line diagrams, design basis descriptions, drawings, calculations of short circuit, voltage drop, protective relay trip setpoints, and the Essential Bus 13-1 loading requirements to evaluate the capability of the 4 kV Bus to supply the voltage and current requirements to one train of essential loads. The inspectors reviewed the short circuit, voltage drop, bus, and feeder protective relay trip settings to verify they were not exceeded and the bus undervoltage and overcurrent relays were appropriately coordinated for fault conditions. The inspectors reviewed the licensees evaluation and subsequent corrective actions for the degraded grease in Merlin Gerin circuit breakers.

Records of system voltage profiles were reviewed from the load flow calculations to verify they were consistent with the design basis assumptions. The inspectors verified the feeder cable size and ampacity was adequate to carry the maximum load current. The inspectors also verified the maximum short circuit current available at the bus was within the interrupting capacity of the feeder breaker.

The inspectors reviewed the 125Vdc voltage drop calculations to verify the control components for the 4 kV breakers had sufficient voltage to operate. Also, the inspectors reviewed the 4 kV breaker setpoints to verify the coordination of the load breakers and the Bus feeder breaker. The inspectors also reviewed the licensees practice for periodic replacement of Agastat relays used in various control circuits. The inspectors performed walkdowns of the 4 kV Essential Bus 13-1 to verify circuit breaker control switches and breaker position indicating lights were consistent with design drawings.

• Standby Liquid Control (SBLC) System Pump (1-1102-A): The inspectors reviewed system hydraulic calculations such as NPSH and minimum flow required to ensure the pump was capable of providing its accident mitigating function. Design change history, corrective actions, surveillance results, and trending data were reviewed to assess potential component degradation and impact on design margins. The inspectors reviewed the modification to increase the sodium pentaborate tank Boron 10 enrichment thereby requiring only one SBLC pump. The inspectors ensured the pump testing met the requirements of Unit 1 License Amendment 235, design calculations, and TS surveillance requirements. The inspectors reviewed control and schematic diagrams to confirm that the operation of pump conformed to the design requirements and operating procedures. The inspectors also reviewed the instrumentation used for the operation of the pump, power supply, and setpoint calculations. The review also verified that the pump motor was adequately protected and that adequate control voltage was available for the operation of the control components. The inspectors reviewed voltage drop calculations to determine whether the pump motor had adequate voltage for running and starting and that the power and control cables had adequate ampacity for the operating conditions.

• Recirculation Pump Trip (RPT)/Alternate Rod Insertion (ARI): The inspectors reviewed control, schematic, and logic diagrams associated with RPT/ARI in response to an ATWS scenario to verify their operation conformed to the design requirements and operating procedures. The testing procedures for RPT/ARI logic were reviewed to verify the logic was adequately tested. The inspectors reviewed the voltage drop calculations to verify the control components in the RPT/ARI circuits have adequate voltage to operate properly. The inspectors also reviewed the operations procedures for manually initiating ARI system and verified the procedures can be performed as written.

• Diesel Generator Cooling Water (DGCW) Pump (DGCWP 1-3903): The inspectors reviewed DGCW pump parts material changes when modified during the 2008 through 2011 timeframe to verify the material was acceptable for the environmental conditions and pump performance was adequately reflected in the DGCW system flow balance, design calculations, and surveillance test acceptance criteria. Calculations for normal and design basis accident conditions were reviewed to verify that sufficient DGCW system flow and NPSH were available for worst case conditions including minimum screenhouse intake bay level and maximum temperature. System operating procedures were reviewed to determine whether design basis conditions were reflected in procedures. Test results were reviewed to ensure pump performance was consistent with the IST acceptance criteria and results were monitored for signs of pump degradation. The inspectors reviewed elementary diagrams to confirm that the pump operation conformed to the design requirements. The inspectors reviewed the one-line diagram and the motor overload protection calculation to confirm proper selection of the motor circuit and motor overload protection. The voltage drop calculations were reviewed to determine whether the motors had adequate voltage for starting and running under degraded voltage conditions and that the motor circuit cabling had adequate ampacity. The inspectors also reviewed control voltage to verify it was adequate for operation of the motor starter contactor. The inspectors reviewed the adequacy of the motor size based on worse case design conditions affecting pump break horsepower. The inspectors reviewed the certified pump vendor performance data to confirm that the analyzed value for pump motor load in the load flow analysis was consistent with the vendor data for the pump break horsepower requirement.

• 480Vac Reactor Building Essential Service Motor Control Center (MCC 18-1A):

The inspectors reviewed the one-line diagram, the load flow analysis, the short circuit current calculation, and the coordination calculation to confirm the short circuit duty and the proper coordination between the MCC breakers with the upstream protective device. The inspectors reviewed the breaker calibration test results to confirm the main incoming breaker settings were in conformance with the coordination analysis. The inspectors also reviewed the load flow and short circuit duty requirement to confirm the adequacy of the motor control center bus and circuit breaker interrupting ratings.

b. Findings

(1) Failure to Identify Aging Effects on Plant Equipment and Structures

Introduction:

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to effectively identify, evaluate, and document aging effects on plant equipment and structures as part of the licensees Aging Management Programs (AMPs) for a plant within its period of extended operation. The inspectors identified two corroded pipe supports and associated base plates in the Unit 1 HPCI room as well as a severely corroded nut and stud on the 1/2 DGCW pump outboard mechanical seal.

These conditions had not been previously documented in the licensees Corrective Action Program.

Description:

The inspectors performed limited walkdowns of plant equipment and structures as part of the inspection activities for the selected components. These walkdowns included the Unit 1 HPCI pump and associated equipment, as well as the 1/2 DGCW pump and associated equipment. These walkdowns were performed to verify the material condition of plant equipment and structures. During two separate walkdowns, the inspectors identified adverse conditions that had not been previously documented by plant personnel.

• The inspectors identified two pipe support base plates in the Unit 1 HPCI room that were corroded due to apparent ground water intrusion through the south wall. One support was associated with line 1-2342-12-C (HPCI pump test line), and the other was associated with line 1-2315-4-LX (HPCI cooling water line). The licensee stated that this condition had not been previously identified, evaluated, and documented.

The inspectors questioned why this condition had not been previously identified and documented by the licensees AMP for Structures Monitoring to facilitate monitoring of age-related degradation. The licensee stated that the subject pipe supports were not within the sample set of structural components specifically monitored by ER-AA-450, Structures Monitoring Program. The licensee also stated that the Unit 1 HPCI room was subject to a structural examination on a 5-year frequency and that one pipe support in the room was within the sample set of the program; this pipe support was not located on the exterior wall affected by ground water intrusion. The inspectors reviewed the most recent Structures Monitoring report for the Unit 1 HPCI room, completed on July 13, 2012; the report stated that, All component supports were found to be acceptable, with only minor water seepage noted on the exterior wall.

The licensee stated that the Structures Monitoring Program also relied on routine walkdowns for the identification of degraded conditions. The inspectors reviewed the most recent system engineers walkdown checklist for the Unit 1 HPCI system, completed on November 20, 2014, which was performed after the inspectors walkdown. The checklist stated that, Material condition of components, supports, hangers are acceptable.

In response to the inspectors identification of this condition, the licensee initiated Action Request (AR)02407265 on November 4, 2014. The licensee stated that the supports were evaluated utilizing the criteria from the Structures Monitoring Program, ER-AA-450, and found to be capable of performing their structural functions. Based on a structural engineering review, the licensee determined that the supports were acceptable with deficiencies.

• On November 20, 2014, the inspectors identified a severely corroded nut and stud on the 1/2 DGCW pump outboard mechanical seal. This corrosion appeared to have significantly reduced the mechanical integrity of the lowest nut and stud affixing the outboard gland seal plate to pump. In addition, the inspectors found the other three nuts and studs on the seal plate to be moderately corroded. The licensee stated that this condition had not been previously identified and documented.

The inspectors questioned why this condition had not been previously identified and documented by the licensees AMP for Bolting Integrity or Open-Cycle Cooling Water to facilitate monitoring of age-related degradation. The licensee stated the AMPs rely on routine walkdowns, including system engineers quarterly walkdowns, for the identification of degraded conditions. The licensee did not identify the corrosion issue during routine system walkdowns. The inspectors noted that there was a deficiency tag on the DGCW pump, but it only addressed the pump casing, which needed to be cleaned (2012). However, the degradation on the seal nuts and bolts was not identified even though they were in close proximately to the identified condition. The inspectors also noted that licensee personnel had performed QCOS-06, Diesel Generator Cooling Water Pump flow Rate Test, on the 1/2 DGCW pump on September 29, 2014. Steps H.3.b and H.3.p.(1) of QCOS-06 required a visual inspection of the DGCW pump, and associated piping and valves for leakage. Licensee personnel did not identify the corrosion on the mechanical seal during performance of this test.

In response to the inspectors identification of this condition, the licensee initiated AR02415422. The licensee assessed the condition of the pump and determined that it was operable because the corroded nuts and studs were still capable of maintaining the seal intact and there was no visible seal leakage. In addition, the pump had passed all recent surveillance tests and the gland seal plate only had to resist low system pressure. The AR stated that the nuts and studs would be inspected and replaced as required.

Because the inspectors identified several adverse conditions not previously identified and documented by plant personnel, the inspectors questioned the effectiveness of the AMPs to identify age-related degradation to ensure they were adequately monitored, assessed for functional capability, and corrected as needed. The inspectors questioned how degraded conditions were being monitored, and observed that neither the Structures Monitoring reports nor the system engineers walkdown checklist included descriptions or other documentation of age-related degradation that was determined to be acceptable. The inspectors determined that the licensee had not effectively identified, documented, or monitored these degraded conditions. In response to these concerns, the licensee initiated AR02420743 on December 4, 2014.

The licensee provided the inspectors a number of recent ARs that identified corrosion issues. The inspectors review determined the issues that were identified appeared to be adequately addressed by the programs such that the inspectors' concern was related to the thoroughness of the inspections/walkdowns in identifying issues that need to be either monitored or corrected.

Analysis:

The inspectors determined that the failure of licensee personnel to effectively identify, and evaluate aging effects on structures and plant equipment was a performance deficiency that warranted a significance evaluation. The performance deficiency was determined to be more than minor and a finding in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, the failure of licensee personnel to effectively identify and evaluate aging effects on plant equipment and structures could allow equipment to continue to degrade to failure. For example, with additional degradation, DGCW pump seal plate may begin to leak and eventually fail. Failure of the 1/2 DGCW pump would result in the loss of the 1/2 emergency diesel generator (EDG). Therefore, this condition, if left uncorrected, could lead to undetected corrosion failures in carbon steel components affecting the reliability and capability of the DGCW system. Similarly, the continued corrosion on HPCI pipe supports could lead to a loss of structural integrity of safety-related pipe supports and affect the capability of the HPCI system to perform its safety function.

The inspectors determined the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase I-Initial Screening and Characterization of Findings, Table 4a for the Mitigating System cornerstone. The finding screened as very low safety significance (Green) because the inspectors were able to answer No to each screening question, because the conditions had not yet affected structural integrity or operability of the systems. Specifically, the licensee confirmed the HPCI supports would be capable to perform their function and the remaining bolts on the mechanical seal were sufficient to prevent excessive leakage.

The inspectors identified a cross-cutting aspect associated with this finding in the area of Human Performance, Resources component, because the licensee did not ensure that personnel, equipment, procedures, and other resources are adequate to assure nuclear safety by maintaining long term plant safety. [H.1]

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected.

Contrary to the above, as of November 4, 2014, and November 20, 2014, respectively, the licensee failed to identify conditions adverse to quality. Specifically, the inspectors identified aging effects on plant equipment and structures that were not previously identified by the licensees Aging Management Programs. This included two corroded pipe supports and associated base plates in the Unit 1 HPCI room as well as a severely corroded nut and stud on the 1/2 DGCW pump outboard mechanical seal.

Because this violation was of very low safety significance, and it was entered into the licensees Corrective Action Program as AR02415422, AR02407265, and AR02420743, which concluded the deficient equipment could perform their intended function, this violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2 of the NRC Enforcement Policy. [NCV 05000254/2014008-01; 05000265/2014008-01, Failure to Identify Aging Effects on Plant Equipment and Structures.]

(2) Non-Conservative DGCW Pump Break Horsepower Assumed in EDG Loading Analysis

Introduction:

The inspectors identified an unresolved item (URI) regarding the motor load measured by the licensee for the Unit 1 DGCW pump that was determined to be less than the vendor certified pump performance data and pump load break horsepower (BHP) requirement at maximum flow conditions. Field measured pump motor load data was evaluated by the licensee and utilized as a design input in the Electrical Transient Analysis Program (ETAP) analysis for the emergency bus loading on offsite power and for the bus loading when powered by the EDG.

Description:

The licensee did not fully evaluate and reconcile the effects on electrical bus and EDG loading analyses for the required pump BHP for the expected pump flow conditions, when the Unit 1 DGCW pump impeller was replaced in 2011 under work order (WO) 01301062 and evaluated under engineering change (EC) 369825. This condition was entered into the corrective action program as AR2420101 and AR2420905.

The inspectors noted the licensee did not use vendor certified pump performance data when they evaluated the effects of the pump impeller replacement on the motor load.

Instead, the licensee used field measured electrical load data as a design input to the ETAP electrical calculations for bus load flow and EDG loading, which the inspectors determined resulted in the bus and EDG loading being non-conservative. Technical Specification surveillance requirement (SR) 3.8.1.15 required loading the EDG between 2340 and 2600 kW for 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> and between 2730 and 2860 kW for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

The inspectors determined for the 1/2 EDG (which the licensee identified had the worst case loading), the margin between the actual EDG accident loading and the 2-hour minimum surveillance limit of 2730 kW was further reduced as a result of the increase in required pump brake horsepower from 90 to 101 BHP based on vendor certified pump performance data. The licensee concluded the pump brake horsepower increased only 5 HP, from 90 to 95 BHP, based on their field measurements of voltage and line current, but failed to reconcile the 5 HP load increase with vendor certified pump performance curve, which required approximately 101 BHP, or an 11 HP increase, at the established flow condition (1650 gpm). The licensee determined the additional increase in pump horsepower, when considering the vendor certified BHP for the pump at maximum flow conditions, remained within the minimum 2-hr load capability requirement established for TS SR 3.8.1.15.

The inspectors determined the vendors pump load requirement derived from the certified pump performance curve of 101 BHP was approximately 6 HP more than the load determined by the licensee by field measurement of motor current and voltage.

Field measurement of motor current and voltage was a licensee approved method in standard NES-EIC-11.01, Use of Analytical Software for AC Auxiliary Power System Analysis, to determine pump horsepower load for input to the ETAP analysis. The inspectors were concerned that if other load inputs to ETAP, derived from the measurement of voltage and current conditions, were also found to be less than actual maximum design basis load conditions, the EDG load could be adversely impacted.

Resolution of this issue will be based on a licensee evaluation for the extent of condition for any additional impact on the subject bus loading conditions. Pending resolution, this item will be tracked as an unresolved item. [URI 05000254/2014008-02; 05000265/2014008-02, Non-Conservative DGCW Pump Break Horsepower Assumed in EDG Loading

Analysis.

]

(3) Testing of MSIVs with Instrument Air or Drywell Pneumatic System Aligned to Actuators

Introduction:

The inspectors identified an unresolved issue (URI) regarding the testing of the MSIVs. Specifically, the inspectors identified the MSIV closure timing surveillance tests were performed with non-safety related instrument air or the drywell pneumatic system aligned to the actuators. The inspectors were concerned that the surveillance test acceptance criteria could be non-conservative.

Description:

The inspectors reviewed surveillance test Procedure QCOS 0250-04, MSIV Closure Timing, and noted the MSIV fast closure testing (required by TS surveillance requirement (SR) 3.6.1.3.6 and the IST Program) was performed with non-safety-related instrument air or the drywell pneumatic system aligned to the actuators. The MSIVs were designed with safety-related accumulators to provide pressure to assist in closing the valves; however these air accumulators would be expected to provide less pressure than the non-safety-related instrument air or drywell pneumatic systems. Technical Specification SR 3.6.1.3.6 required verification that the isolation time of each MSIV will be 3 seconds and 5 seconds. The inspectors observed test Procedure QCOS 0250-04 included separate closure time acceptance criteria for hot and cold conditions, but did not include any acceptance criteria adjustments for the use of non-safety-related instrument air or the drywell pneumatic system. The inspectors were concerned the surveillance test maximum closing time acceptance criteria ( 5 seconds for cold valves) could be non-conservative. This concern was previously addressed by NRC IN 85-84, Inadequate Inservice Testing of Main Steam Isolation Valves. At that time, the licensees review of IN 85-84 stated the MSIV air supply isolation valve was closed during testing. On February 22, 1989, General Electric Nuclear Services Information Letter (SIL) No. 482 was issued to address the effect of non-safety related air on the closure time testing of some MSIVs.

The SIL indicated that testing of two Boiling Water Reactor MSIVs equipped with hydraulic self-compensation mechanisms resulted in a time increase of about 0.1 seconds when the non-safety-related air supply was disconnected. The installed MSIVs were also equipped with hydraulic self-compensation mechanisms. The SIL No. 482 also recommended testing to verify the effect of removing non-safety related air supplies. The SIL stated that if the closure time with the air disconnected increased less than 0.3 seconds, it would be acceptable to leave the non-safety-related air connected during closure time testing. The 0.3 second criterion was based on a typical total allowable variation of 0.5 seconds. This 0.5 margin was based on an historical practice of setting MSIV closure times between 3.5 and 4.5 seconds (light to light). In addition, the historical accident analyses were based on the MSIVs closing in less than 10 seconds (plus an additional 0.5 second allowance for instrument/control response). The current alternate source term accident analysis was based on the MSIVs closing within 5 seconds (plus an additional 0.5 second allowance for instrument/control response)under accident conditions (UFSAR Section 15.6.4.5.1). Based on the current alternate source term analysis, there was no allowance for margin between the as-found surveillance test acceptance criterion, the TS limit, and the analytical limit. It was unclear to the inspectors whether the licensees basis to revise the test methodology to having non-safety air un-isolated was based on the SIL.

The licensees evaluation of SIL No. 482, dated June 27, 1989, stated the MSIVs were tested with the non-safety-related instrument air or drywell pneumatic system aligned to the actuators. The evaluation also stated a special test was required to determine the effect of air pressure on MSIV closure time. The licensee determined the special test was performed with acceptable results to justify continued closure time testing with the non-safety related instrument air or the drywell pneumatic system aligned to the actuators. However, the actual test results were lost in the late 1980s due to a computer records failure. The licensee initiated AR02420923 on December 4, 2014, to address this issue.

The licensee was able to obtain MSIV closure time special test results for eight similar MSIVs from Dresden Station, performed in May 1992. The results indicated an average closure time increase of less than 0.1 seconds with non-safety related air disconnected.

However, there was considerable variation in the individual MSIV test results. Based on the Dresden special test results, the records indicating that a special test was performed successfully, the most recent as-left MSIV closure time test results, and documentation from General Electric, the licensee determined the MSIVs remained operable.

Resolution of this issue will be based on additional analysis and/or testing by the licensee. This analysis/testing will determine if additional surveillance test acceptance criteria margin and/or a change in testing methodology will be required to ensure the MSIVs will close in the required time under the most limiting conditions. Specifically, the inspectors were concerned the current testing methodology (with the non-safety-related instrument air or drywell pneumatic system aligned to the actuators)could result in the MSIVs stroking faster than the most limiting accident conditions, with only safety-related accumulators available, which appeared to be a change from the testing methodology prior to IN 85-84. The inspectors were also concerned the recommendations of SIL No. 482 were not applicable to the current licensing/design basis because those recommendations were based on an assumed total allowable variation of 0.5 seconds. As discussed above, the alternate source term analysis (performed after the SIL was issued) did not include any closure time margin beyond the as-found surveillance test acceptance criterion and the upper TS time limit. It appeared that any non-conservatism in the test methodology would be unacceptable unless the test acceptance criteria included explicit allowances for the difference between the test conditions and the most limiting accident conditions. Pending resolution, this item will be tracked as an unresolved item. [URI 05000254/2014008-03; 05000265/2014008-03, Testing of MSIVs with Instrument Air or Drywell Pneumatic System Aligned to Actuators.]

.4 Operating Experience

a. Inspection Scope

The inspectors reviewed three operating experience issues 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:

• IN 84-20, Service Life of Relays in Safety-Related Systems,

• IN 2009-09, Improper Flow Controller Settings Renders Injection Systems Inoperable and Surveillance Did Not Identify; and

• IN 2009-10, Transformer Failures - Recent Operating Experience.

b. Findings

No findings of significance were identified.

.5 Modifications

a. Inspection Scope

The inspectors reviewed four 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:

• EC 351280, Replacement of Reserve Auxiliary Transformer;

• EC 349585, Increased the Sodium Pentaborate Tank Boron 10 Enrichment to Greater than or Equal to 45 Atomic Percent from 30 Atomic Percent thereby Requiring only one SBLC Pump;

• EC 365401, SBLC System Operation change from 2 Pumps to 1 Pump; and

• EC 355357, Replace Unit 1 DGCW Pump with Low NPSH Impeller.

b. Findings

No findings of significance were identified.

.6 Operating Procedure Accident Scenarios

a. Inspection Scope

The inspectors verified the licensed operators could perform risk significant, time critical operator actions associated with anticipated transient without scram (ATWS) events within the time assumed per design document OPTIMA2-TR026QC-ATWS.

These actions were selected from the licensees PRA rankings of human action importance based on risk-achievement worth values. Where possible, margins were determined by the review of the assumed design basis and UFSAR response times and performance times documented by job performance measures and simulator scenario results. For the selected operator actions, the inspectors performed a detailed review and walk through of associated procedures, including observing the performance of simulated manual actions in the plant. Additionally, a licensed operator crew was evaluated for time critical actions using the stations simulator. The inspectors evaluated the manual actions both in-plant and in the simulator to assess operator knowledge level, and adequacy of procedures used and human actions performed as a result of an ATWS event. The procedures were compared to UFSAR, design assumptions, and training materials to verify consistency.

The following Time Critical Actions (TCAs) were evaluated:

• TCA12, Initiate SBLC during an ATWS with 110°F torus temperature;

• TCA13 , Initiate drywell sprays during an ATWS with >2.5 psig drywell pressure or drywell temperature >281°F;

• TCA14, Isolate feedwater during an ATWS; and

• TCA16 , Initiate suppression pool cooling during an ATWS.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered Into the Corrective Action Program

a. Inspection Scope

The inspectors reviewed a sample of the selected component problems identified by the licensee and entered into the corrective action program. The inspectors 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 corrective action program. The specific corrective action documents sampled and reviewed by the inspectors are listed in the Attachment to this report.

The inspectors also selected three issues identified during previous CDBIs to verify that the concern was adequately evaluated and corrective actions were identified and implemented to resolve the concern, as necessary. The following issues were reviewed:

• NCV 5000254/265/2011009-03; Safety-Related Battery Charger Testing and Maintenance Procedures Did Not Include Steps for Electrolytic Capacitor Replacement;

• NCV05000254/265/2008007-01; Use of Non-Conservative Inputs and Methodologies in Calculating Terminal Voltages to Safety-Related MOV Motors During Design Basis Events; and

• URI 05000254/265/2011009-05 and NCV 05000254/265/2012005-01; Diesel Generator Technical Specification Frequency and Voltage Variation not Considered in Loading Calculations.

b. Findings

No findings of significance were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On December 5, 2014, the inspectors presented the inspection results to Mr. S. Darin, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. Several documents reviewed by the inspectors 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

S. Darin, Site Vice President

K. OShea, Plant Manager

R. Alkan, Electrical Design Engineer

W. Beck, Regulatory Assurance Manager

B. Brewer, System Engineer

H. Dodd, Site Maintenance Director

M. Dunlay, Mechanical Design Engineer

Y. Fedorov, Electrical Design Engineer

M. Fritch, Operations

J. Friedrichsen, Acting Nuclear Oversight Manager

S. Gundlach, Operations

M. MacLennan, Operations

K. Ohr, Site Engineering Director

T. Petersen, Regulatory Assurance

B. Stedman, Senior Engineering Manager

R. Swart, Design Engineering Manager

M. Uhrich, Mechanical Design Engineer

B. Wake, Shift Operations Superintendent

Nuclear Regulatory Commission

R. Murray, Senior Resident Inspector

K. Carrington, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000254/2014008-01; NCV Failure to Identify Aging Effects on Plant Equipment

05000265/2014008-01 and Structures (Section 1R21.3.b.(1))

05000254/2014008-02; URI Non-Conservative DGCW Pump Break Horsepower

05000265/2014008-02 Assumed in EDG Loading Analysis (Section 1R21.3.b.(2))

05000254/2014008-03; URI Testing of MSIVs with Instrument Air or Drywell

05000265/2014008-03 Pneumatic System Aligned to Actuators (Section 1R21.3.b.(3))

Closed

05000254/2014008-01; NCV Failure to Identify Aging Effects on Plant Equipment

05000265/2014008-01 and Structures (Section 1R21.3.b.(1))