IR 05000244/2013007

IR 05000244/2013007; 7/22/2013 to 8/22/2013; R.E. Ginna Nuclear Power Plant, LLC (Ginna); Component Design Bases Inspection

ML13275A041
Person / Time
Site:	Ginna
Issue date:	10/01/2013
From:	Paul Krohn Engineering Region 1 Branch 2
To:	Joseph Pacher Constellation Energy Nuclear Group, Ginna
References
IR-13-007
Download: ML13275A041 (35)

Text

UNITED STATES ber 1, 2013

SUBJECT:

R.E. GINNA NUCLEAR POWER PLANT, LLC - NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000244/2013007

Dear Mr. Pacher:

On August 22, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the R.E. Ginna Nuclear Power Plant, LLC (Ginna). The enclosed inspection report documents the inspection results, which were discussed on August 22, 2013, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

In conducting the inspection, the team examined the adequacy of selected components and operator actions to mitigate postulated transients, initiating events, and design basis accidents.

The inspection involved field walkdowns, examination of selected procedures, calculations and records, and interviews with station personnel.

This report documents one NRC-identified finding which was of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance of the violation and because it was entered into your correction action program, the NRC is treating this violation as a non-cited violation (NCV)

consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the NCV in this report, 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, D.C. 20555-0001, with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C.

20555-0001; and the NRC Resident Inspector at Ginna. In addition, if you disagree with the cross-cutting aspect assigned to the 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 I; and the NRC Resident Inspector at Ginna. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for the public inspection in the NRC Public Docket Room or from the Publicly Available Records component of NRCs document 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/

Paul G. Krohn, Chief Engineering Branch 2 Division of Reactor Safety Docket No. 50-244 License No. DPR-18

Enclosure:

Inspection Report 05000244/2013007 w/Attachment: Supplemental Information

REGION I==

Docket No.: 50-244 License No.: DPR-18 Report No.: 05000244/2013007 Licensee: Constellation Energy Nuclear Group, LLC (CENG)

Facility: R.E. Ginna Nuclear Power Plant, LLC Location: Ontario, NY Dates: July 22 to August 22, 2013 Inspectors: F. Arner, Senior Reactor Inspector, Division of Reactor Safety (DRS),

Team Leader P. Kaufman, Senior Reactor Inspector, DRS J. Ayala, Reactor Inspector, DRS J. Brand, Reactor Inspector, DRS G. Gardner, NRC Mechanical Contractor J. Nicely, NRC Electrical Contractor Approved by: Paul G. Krohn, Chief Engineering Branch 2 Division of Reactor Safety i Enclosure

SUMMARY OF FINDINGS

IR 05000244/2013007; 7/22/2013-8/22/2013; R.E. Ginna Nuclear Power Plant, LLC (Ginna);

Component Design Bases Inspection.

The report covers the Component Design Bases Inspection conducted by a team of four NRC inspectors and two NRC contractors. One finding of very low risk significance (Green) was identified; this finding was considered to be a non-cited violation (NCV). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The team identified a finding of very low safety significance involving a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, in that,

Constellation did not ensure the automatic load tap changer (LTC) controls and motor for the #7 transformer and the circuit 767 voltage regulator associated with the

1. 6 transformer had adequate voltage to operate during design basis events.

Specifically, LTC operation is credited to restore vital bus voltage during design basis events under minimum grid voltage conditions. Additionally, appropriate acceptance criteria had not been translated into periodic LTC timing tests to ensure design assumptions were being maintained. Failure of the automatic LTC controls and motor to operate, as credited, due to inadequate voltage or timing would result in the 480V safeguard buses disconnecting from one of its credited sources of power. Constellation entered the issue into their corrective action program, performed preliminary voltage calculations, and tested a spare LTC motor at voltage levels below the vendor minimum voltage ratings to ensure the offsite power source would remain operable to the safeguard buses.

The finding was more than minor because it was similar to Example 3.j of NRC IMC 0612, Appendix E, and was associated with the Design Control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined the finding was of very low safety significance because the issue was a design deficiency that did not result in the loss of the preferred source of power to the 480V safeguard buses. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience, because in 2011 Ginna had previously recognized operating experience information noting that the station may be vulnerable to the issue of evaluating LTC control voltage. However, Constellation had not implemented this operating experience into their station processes to ensure they had correctly analyzed the issue. [IMC 0310,

Aspect P.2 (b)] (Section 1R21.2.1.1)ii

Licensee-Identified Violations

None iii

REPORT DETAILS

1R21 Component Design Bases Inspection (IP 71111.21)

.1 Inspection Sample Selection Process

The team selected risk significant components for review using information contained in the Ginna Station Probabilistic Risk Assessment (PRA) and the U.S. Nuclear Regulatory Commissions (NRC) Standardized Plant Analysis Risk (SPAR) model. Additionally, the Ginna Significance Determination Process (SDP) analysis was referenced in the selection of potential components for review. In general, the selection process focused on components that had a Risk Achievement Worth (RAW) factor greater than 1.3 or a Risk Reduction Worth (RRW) factor greater than 1.005. The team also selected components based on previously identified industry operating experience issues and the component contribution to the large early release frequency (LERF) was also considered. The components selected were located within both safety-related and non-safety related systems, and included a variety of components such as pumps, breakers, heat exchangers, electrical buses, transformers, and valves.

The team initially compiled a list of components based on the risk factors previously mentioned. Additionally, the team reviewed the previous component design bases inspection reports (05000244/2007006 and 05000244/2010009) and excluded those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 20 components and 3 operating experience (OE)samples. One isolation valve component was selected because of its potential impact for LERF implications. The teams evaluation of possible low design margin conponents included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment also included items such as failed performance test results, corrective action history, repeated maintenance, maintenance rule (a)1 status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry operating experience. Finally, consideration was given to the uniqueness and complexity of the design and the available defense-in-depth margins.

The team inspection was conducted in accordance with NRC Inspection Procedure 71111.21. This inspection effort included: walkdowns of selected components; interviews with operators, system engineers, and design engineers; and reviews of associated design documents and calculations to assess the adequacy of the components to meet the design and licensing basis. A summary of the reviews performed for each component, operating experience sample, and the specific inspection findings identified are discussed in the subsequent sections of this report.

Documents reviewed for this inspection are listed in the Attachment.

.2.1.1 480V Buses 14 and 17 (2 samples)

a. Inspection Scope

The team inspected the 14 and 17 480V buses to evaluate whether they were capable of meeting their design basis requirements. The team reviewed the design and operation of the switchgear bus and associated distribution panels. The team reviewed selected calculations for distribution system load flow/voltage drop, degraded voltage protection, short-circuit, and electrical protection and coordination. Design assumptions and calculations were reviewed to verify that bus capacity was not exceeded and bus voltages to safety-related devices at all voltage distribution levels remained above minimum acceptable values for worst case accident loading and grid voltage conditions.

The switchgears protective device settings and breaker rating were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst-case short-circuit conditions. The team reviewed the automatic and manual transfer schemes between alternate offsite sources and the emergency diesel generators (EDG).

The team verified that degraded and loss-of-voltage relays were set in accordance with calculations and that associated calibration procedures were consistent with calculation assumptions, associated time delays, and setpoint accuracy. The latest surveillance tests were reviewed to ensure components met the design requirements. The team evaluated the stations interface and coordination with the transmission system operator for station voltages requiring plant notifications. The team reviewed the preventive maintenance inspection and testing procedures associated with bus breakers to ensure they were maintained in accordance with industry and vendor recommendations. The team also reviewed selected operating procedures to ensure the components were operated consistent with design requirements. The 125Vdc voltage calculations were reviewed to ensure adequate voltage would be available to the breaker closure and opening control circuit. The team performed a visual, non-intrusive inspection of observable portions of the safety-related 480V switchgear to assess the installation configuration, material condition, and potential vulnerability to hazards. System health reports, component maintenance history, and corrective action program reports were reviewed to verify deficiencies were identified and corrected.

1.

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, in that, Constellation did not ensure the automatic load tap changer (LTC) controls and motor for the #7 transformer and the circuit 767 voltage regulator associated with the #6 transformer had adequate voltage to operate during design basis events. Specifically, LTC operation is credited to restore vital bus voltage during design basis events under minimum grid voltage conditions. Additionally, appropriate acceptance criteria had not been translated into periodic LTC timing tests to ensure design assumptions were being maintained. Failure of the automatic LTC controls and motor to operate, as credited, due to inadequate voltage or timing would result in the 480V safeguard buses disconnecting from one of its credited sources of power.

Description:

The team noted that electrical calculation, DA-EE-96-068-03, Offsite Power Load Flow Study, Revision 6, credited 16 taps in approximately 53 seconds for the

1. 7 offsite power transformer and 17 taps in approximately 70 seconds for the circuit 767 voltage regulator associated with the #6 transformer. These taps were credited to recover voltage levels above the degraded voltage relays on the 480V safeguards buses during a design basis accident event under minimum grid voltage conditions. The team questioned whether there was sufficient voltage supplied to the LTC controller and associated motor to prevent it from stalling during the worst-case offsite grid voltage of 108.9kV. In response, Constellation performed a voltage drop calculation from the 34kV connection down to the LTC controllers and motors. The preliminary calculated voltage at the #7 LTC was 88.9 percent of its rating and to the #767 circuit LTC was 87.9 percent of its rating. The team determined that the vendor minimum voltage rating for the LTC controller and motor was 90 percent. The team noted that while motors do not stop operating below the rated voltage, the available torque decreases. During the investigation of the issue Constellation could not initially obtain required torque values for the LTC and therefore performed testing to validate the motor capability at reduced voltages. Constellation performed this testing on a spare motor they obtained which was similar to the installed motor in the circuit 767 regulator. This testing showed that the LTC motors would operate satisfactorily down to 80 percent nominal voltage levels.

The team reviewed the periodic timing testing of the LTCs to ensure that the measured timing was within the time period assumed and credited in calculation DA-EE-96-068-03, which credited 16 taps in 53 seconds for the #7 transformer and 17 taps in 70 seconds for the circuit 767 voltage regulator (#6 transformer). The team determined that there were no acceptance criteria in place relative to the acceptable timing of the taps. The team determined that this lack of criteria could result in untimely identification that the LTCs were not operating in accordance with design assumptions with respect to ensuring the offsite power source would remain available to the 480V safety buses during accident conditions. The team noted that the test results had been reviewed by Constellation personnel, however there were no criteria established to ensure that operation of the LTCs outside their assumed performance would be immediately evaluated for the potential impact of ensuring the safety buses preferred power supply (offsite power operability.) Constellation performed a review of the timing test results to verify that the assumptions in the calculations were still being met and entered the issue into their corrective action program to ensure procedures were consistent with the design assumptions. Interim corrective actions consisted of temporarily revising spreadsheets with conservative time assumptions to confirm that safety margins were maintained.

Analysis:

The performance deficiency associated with this finding was that Constellations design, review, and implementation of their LTC analyses did not verify the adequacy of the supply voltage to the automatic LTC controls and motor for operation during design basis events under minimum grid voltage conditions.

Additionally, appropriate acceptance criteria for LTC timing tests had not been translated into procedures to ensure consistency with these design analyses. Failure of the automatic LTC controls and motor to operate, as credited, due to inadequate voltage or timing would cause the 480V safeguard buses to pre-maturely disconnect from one of its credited sources of power. The finding was more than minor because it was similar to Example 3.j of NRC IMC 0612, Appendix E, "Examples of Minor Issues," in that the team had a reasonable doubt of operability until further analysis of actual voltage drop and testing were performed to ensure capability under the worst case design conditions. In addition, the finding was associated with the Design Control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

The team performed a risk screening, in accordance with IMC 0609, Appendix A, "Significance Determination Process for Findings At-Power," using Exhibit 2, "Mitigating Systems Screening Questions." The team determined the finding was of very low safety significance (Green) because it was a design deficiency that did not result in the loss of operability or functionality of the preferred power supply to the safety-related ESF buses.

Specifically, subsequent voltage drop evaluation and testing confirmed that the LTC controls and motor would have been able to perform under the worst case loading and minimum grid conditions during accident conditions. Additionally, the concern was limited to specific conditions with one offsite line out of service and when Ginna is required to supply volt-ampere reactive (VAR) power to the system. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience, because in 2011 Ginna had previously recognized operating experience information noting they may be vulnerable to the issue of evaluating LTC control voltage.

However, Constellation had not implemented this operating experience into their station processes to ensure they had correctly analyzed the issue. [IMC 0310, Aspect P.2 (b)]

Enforcement:

The Ginna updated final safety analysis report (UFSAR) section 3.1.2.2.8 addresses conformance with General Design Criteria (GDC) 17 for electrical power systems. This criterion states, in part, that an offsite electric power system shall be provided to permit functioning of structure, systems, and components important to safety and that both onsite and offsite power systems have a safety function. 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that design control measures shall provide for verifying or checking the adequacy of design. Contrary to the above, as of August 15, 2013, Constellations design control measures had not verified the adequacy of the LTC controls and motor with respect to ensuring adequate voltage would be available to these components to ensure the availability of the offsite power supply to the ESF safeguard buses during design bases events and limiting grid voltage conditions. Additionally, design control measures had not adequately translated design assumptions into LTC test acceptance criteria. Constellation performed a preliminary voltage evaluation and tested a spare LTC motor at voltage levels below the vendor minimum voltage ratings to ensure the offsite power source would remain operable to the safeguard buses. Additional interim corrective actions consisted of temporarily revising test spreadsheets with conservative time assumptions to confirm that margins were maintained. Because this violation was of very low safety significance (Green) and was entered into Constellations corrective action program as (CRs 2013-004929, 2013-004920 and 2013-004986), this violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2 of the NRC's Enforcement Policy. (NCV 05000244/2013007-01, Required Voltage and Timing Criteria for Load Tap Changer Controls and Motor)

2. Adequacy of the Ginna Station Degraded Voltage Relay Time Delay and Offsite/Station

Electric Power System Design Calculations

Introduction:

The team identified an unresolved item (URI) during the inspection. The team determined that additional NRC review and evaluation is required to determine whether Ginnas licensing and design bases, relative to the design of the degraded voltage relay time delays and offsite power design calculations, were adequate and met all NRC requirements and regulations. During the inspection, the team reviewed the recent guidance issued in NRC Regulatory Issue Summary (RIS) 2011-12, Revision 1, Adequacy of Station Electric Distribution System Voltages. The team determined that Ginnas design analyses and calculations may not be consistent with the guidance contained in the RIS.

Description:

RIS 2011-12 guidance indicated that the licensees voltage calculations should provide the basis for proper operation of the plant safety-related (SR) electrical distribution system, when supplied from the offsite circuits via the transmission network.

These calculations should demonstrate that the voltage requirements (both starting and running voltages) of all plant SR systems and components are satisfied based on operation of the transmission system (including the bounding transmission system single contingency in terms of voltage drop). In addition, during accident conditions, the nuclear unit generator trip and associated transmission system voltage drop should be factored into the accident case voltage calculations since unit trip occurs as a result of the accident. Licensee calculations should also demonstrate that all SR systems and components will function as designed with proper starting and running voltages during all plant conditions and the DVRs will not actuate (separating the transmission network supply).

The team noted that Constellation had not performed calculations to demonstrate that the offsite electric power system had sufficient capacity and capability to assure the voltage requirements for all SR systems and components initiated during the onset of a design basis accident were met. Specifically, Constellation assumed that following the accident signal and resulting turbine trip, that the main generator breaker stays connected as a synchronous condenser providing voltage support for an additional 60 seconds after the reactor trip. After this time delay, relays then open the breaker in the 115 kilovolt (kV) switchyard which results in a 115kV transmission system voltage drop to 108.9kV. This voltage level becomes the source of power to the 480V safety-related buses after the unit generator breaker opens. At this time, however, all of the accident initiated SR loads have already started and sequenced onto the buses as running loads. The team noted that due to the voltage drop at 60 seconds, the SR buses drop to approximately 382V or 79 percent of rated voltage, which is below the degraded voltage relay setting of 420V. Constellation credits operation of the

1. 7 transformer and/or #6 transformer/767 regulator automatic LTC to restore the bus voltages to above the DVR reset within the design time delay of a nominal 68-125 seconds.

The team determined that Constellation had not performed dynamic motor starting calculations to evaluate the terminal voltages to SR equipment while connected to the onsite main generator or offsite power during accident initiated load sequencing to ensure and demonstrate that the voltage requirements of all plant SR systems and components are satisfied. These calculations had not been performed, in part, because Constellation credits a dynamic emergency diesel generator (EDG) voltage analysis as bounding the voltage drops that would occur if on the main generator or offsite power.

As a result, there are no calculations that show the voltage profile of the 480V SR buses, the terminal voltage of SR motors during motor starting and sequencing, or whether the DVR setpoints are exceeded or reset during the load sequencing event. The team determined that based on the assumption of reliance on the generator to boost voltage, the effect of the EDG being a bounding calculation may be technically accurate.

However, the design assumption of the generator providing this voltage boost may be inconsistent with the RIS 2011-12 guidance for what is assumed in showing that offsite power, independently can provide the source of power to ensure engineered safety feature (ESF) loads have the proper voltage supply during sequencing.

Degraded Voltage Relay Scheme Constellation uses an inverse-time delay (TD) ITE 27 undervoltage relay for the degraded voltage relays. The time delay as specified in TS SR 3.3.4.2 is68-125 seconds at 420V. The team noted that the DVR time delay exceeds the TD for Ginna assumed in the UFSAR accident analyses, which is a nominal 10 seconds and is the time required for the EDGs to start and be ready to accept load. The team also determined that Constellation had not performed an analysis to verify that all SR equipment would not become unavailable due to protective device actuation for a degraded voltage within the bandwidth of the DVR and loss-of-voltage (LOV) setpoints for the existing time delay prior to re-sequencing onto the EDGs. The team reviewed the March 26, 1981, Amendment 38 to the operating license No. DPR-18, which docketed that the original TD setting of 8.5 seconds to above 1000 seconds, ensured that all Class 1E motors will start successfully and be loaded onto the EDG within the time assumed in the FSAR accident analysis. The team could not determine what the basis for this conclusion was because the TD approved was an inverse time characteristic which appeared to have a range outside of existing accident analyses assumptions for the timing of core re-flood during the limiting design basis accident.

In response to the teams concerns, Constellation entered the issue into their corrective action program as CR-2013-004767 for further review recognizing that while the TD is consistent with their approved licensing bases, it is not consistent with current NRC guidance. The team will coordinate with the NRCs Office of Nuclear Reactor Regulation to review the adequacy of Constellations approved licensing and design bases to evaluate whether this issue constitutes a violation and to ensure Constellation is meeting all NRC regulations and requirements. Pending resolution of this issue and determination of any potential enforcement actions, this item is an Unresolved Item.

(URI 05000244/2013007-02, Adequacy of Ginnas Licensing and Design Bases for Offsite Power Calculations and Degraded Voltage Relay Time Delays)

.2.1.2 1A Emergency Diesel Generator Electrical Systems

a. Inspection Scope

The team inspected the A EDG electrical systems to evaluate whether they were capable of supporting their design basis functions. Specifically, the team reviewed loading and voltage regulation calculations, including the bases for brake horsepower (BHP) values used to verify that design bases and design assumptions were appropriately translated into calculations and procedures. The team reviewed protection/coordination and short-circuit calculations to verify that the EDG was adequately protected with properly set protective devices during the test mode and emergency operation, including short-circuit capability of the output breaker under worst case fault conditions. The team reviewed calculations to verify that: 1) steady-state and transient loading were within design capabilities; 2) adequate voltage would be present to start and operate connected loads; and 3) operation at maximum allowed frequency would be within the design capabilities. The team reviewed the bases for the EDG load sequence time delay setpoints, calibration intervals, and results of the last equipment calibration. The team reviewed the interfaces and interlocks associated with the 480V Bus 14, including the voltage protection schemes that initiate connection to the EDG, to verify their adequacy. The team performed a walkdown of the EDG to assess the installed configuration and material condition. The team reviewed system health reports, component maintenance history and corrective action documents to evaluate whether issues were appropriately identified and corrected.

b. Findings

No findings were identified.

.2.1.3 Station Service Transformer SST 18

a. Inspection Scope

The team inspected the station service transformer, SST 18, to evaluate whether it was capable of meeting its design basis functions. The team reviewed system one-line diagrams, nameplate data, protective relay setting calculations, and loading requirements to determine the adequacy of the transformer to supply the required preferred offsite power supply to the associated 480V bus. The team reviewed load flow calculations to evaluate whether the transformer was operated within its specified ratings. The team reviewed protective relaying schemes and calculations to evaluate whether the transformer was adequately protected and if it was susceptible to spurious tripping. The team reviewed periodic maintenance and testing practices to ensure the equipment was maintained in accordance with industry practices. The team reviewed system health reports, component maintenance history, and corrective action documents to determine if issues were appropriately identified and corrected. The team performed a walkdown of the observable portions of SST 18 to assess the installed configuration and material condition.

b. Findings

No findings were identified.

.2.1.4 125 VDC Station Battery A

a. Inspection Scope

The team inspected the design, testing, and operation of the direct current (DC)

A station battery to verify that it could perform its design function of providing a reliable source of DC power to connected loads under operating, transient, and accident conditions. The team reviewed design calculations to assess the adequacy of the batterys sizing to ensure it could power the required equipment for the design bases time duration, and at a voltage above the minimum required for equipment operation.

The team reviewed battery room hydrogen monitoring to verify that the hydrogen concentration would stay below flammable limits during normal and postulated accident conditions. The team reviewed battery test results, including discharge tests, to ensure the testing was in accordance with design calculations, plant technical specifications (TSs), vendor recommendations, and industry standards. The team performed a walkdown of the battery and associated distribution panels to assess the material condition of the equipment. The team reviewed corrective action documents and system health reports to evaluate whether there were any adverse operating trends and to assess Constellation's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.5 120 VAC Instrument Bus 1A

a. Inspection Scope

The team inspected the vital alternating current (AC) instrument bus 1A to evaluate whether it was capable of meeting its design basis functions. Specifically, the team evaluated the inverters capability to provide power to safety-related loads including the nuclear instrumentation, reactor protection, and the engineered safety features actuation systems. The team reviewed the analysis that determined the design basis for maximum loading and the inverter equipment vendor ratings for conformance with the design basis. The team also reviewed calculations to evaluate whether the inverter was capable of providing the 120V system loads with adequate voltage during design basis conditions. Additionally, the team reviewed a common mode failure analysis and the inverter qualification testing in order to evaluate whether there was adequate clearing for the 120V system branch circuits during fault conditions. The team conducted walkdowns at the inverter to assess the observable material condition and to evaluate if the installation was in accordance with manufacturer instructions. The team also reviewed the operating and surveillance procedures to evaluate whether the 120V system voltage limits were correctly incorporated. The team reviewed corrective action documents and system health reports to evaluate whether there were any adverse operating trends and to assess Constellations ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.6 Station Auxiliary Transformer 12B

a. Inspection Scope

The team inspected the station auxiliary transformer (SAT) to verify that it was capable of meeting its design basis requirements. The SAT 12B is designed to provide power to the engineered safeguards buses. The team reviewed transformer protective relaying to evaluate whether it afforded adequate protection and prevented adverse interactions that would reduce system reliability. The team reviewed elementary wiring diagrams for the associated bus feeder and load breakers to verify that control logic was consistent with system design requirements stated in the UFSAR. The team performed walkdowns of the transformer and the associated switchgear to assess the material condition and presence of hazards. The team interviewed system and design engineers to ensure recommended maintenance had been established through the preventive maintenance (PM) program and design changes had been satisfactorily implemented. The team reviewed corrective action documents to evaluate whether there were any adverse trends associated with the transformer and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.7 Anticipated Transient Without Scram Mitigation System Actuation Circuitry

a. Inspection Scope

The team inspected the design and operation of the Anticipated Transient Without Scram (ATWS) mitigating system actuation circuitry. The system design is to provide an alternate means of tripping the turbine and actuating auxiliary feedwater flow independent of the reactor protection system (RPS). The team reviewed elementary logic diagrams for Anticipated Transient Without Scram Mitigation System Actuation Circuitry (AMSAC) to verify that control logic was consistent with system design requirements stated in the UFSAR. The team performed walkdowns of the AMSAC inverter to assess the material condition of the system. The team interviewed Constellation engineers to ensure recommended maintenance had been established through the PM program and design changes had been satisfactorily implemented. The team reviewed corrective action documents to evaluate whether there were any adverse trends associated with the circuitry and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.8 Main Steam Isolation Valve A

a. Inspection Scope

The team inspected the A main steam isolation valve (MSIV) 3517 to verify the valve was capable of performing its design basis function. The team reviewed the UFSAR, TSs, TS Bases, and piping and instrumentation diagrams (P&IDs), applicable plant calculations, and drawings to identify the design bases requirements of the MSIVs. The MSIV is an air-operated valve that closes to isolate the A steam generator on low pressure in one of the steam generators or high containment pressure. The valve is normally open and fails closed on a loss of instrument air at the operating cylinder or fails as-is on loss of direct current (DC) control power to the DC solenoid valves.

The team reviewed valve test procedures and stroke timing data to verify acceptance criteria were within the design basis and that performance was not degrading. The team discussed design, operation, and component history with station engineers to evaluate valve performance history and overall component health. The team reviewed station operating and off-normal response procedures to verify design bases requirements had been adequately translated into procedural instructions. The team conducted a walkdown of the MSIV to assess the material condition and to verify the installed configuration was consistent with plant drawings and procedures. The team reviewed design bases documentation, maintenance records, and drawings of the instrument air system to verify that the support function provided to the MSIV was consistent with design requirements. The team reviewed corrective action documents to evaluate whether there were any adverse trends associated with the MSIV and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.9 Component Cooling Water Heat Exchanger A

a. Inspection Scope

The team inspected the A component cooling water (CCW) heat exchanger (EAC01A)to ensure that it was capable of removing the required heat loads during design basis events. The team performed a walkdown of the heat exchanger, reviewed system health reports, and interviewed the system engineer to evaluate the material condition of the heat exchanger as well as overall component health. The team reviewed design basis documents, eddy current and thermal performance test results, service water full flow test results, heat exchanger cleaning and inspection work orders reports, and completed work orders to verify that the A CCW heat exchanger could maintain adequate heat removal capability and system integrity during design basis events. The team reviewed selected operating procedures for normal, abnormal, and emergency conditions to ensure consistency with the licensing and design bases. The team reviewed corrective action documents to evaluate whether there were any adverse trends associated with the heat exchanger and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 0 Component Cooling Water Pump B

a. Inspection Scope

The team inspected the B CCW pump (PAC02B) to verify that it was capable of meeting its design basis requirements. The CCW system is designed to provide cooling water to essential components under normal, transient, and accident conditions. The team reviewed the UFSAR, drawings, design basis documents, and procedures to identify the most limiting requirements for the pump. The team reviewed inspection and testing procedures to verify that appropriate preventive maintenance and surveillance activities were being performed. The team reviewed a sample of surveillance test results to verify that pump performance met the acceptance criteria and that the criteria were consistent with the design basis. The team reviewed calculations for NPSH to ensure that the pump could successfully operate under the most limiting conditions. The team discussed the design, operation, and corrective maintenance of the pump with engineering staff to gain an understanding of the performance history and overall component health. The team reviewed calculations that established voltage drop, ampacity, protection and coordination, motor brake horsepower requirements, and short circuit ratings for the motor power supply and feeder cables to verify that design bases and design assumptions were translated into design calculations. The team reviewed the maintenance and operating history, system health reports, and surveillance test results to evaluate whether there were any adverse operating trends and to ensure that Constellation adequately identified and addressed deficiencies.

b. Findings

No findings were identified.

.2.1.1 1 Service Water Pump A

a. Inspection Scope

The team inspected the A service water (SW) pump to verify that the pump was capable of performing its design basis function. The SW pumps provide an adequate supply of cooling water flow to safety-related components and perform the function of heat removal from equipment during accident conditions. The team reviewed the in-service test (IST) reference values for flowrate and total developed head (TDH) along with acceptance criteria to ensure that minimum pump performance was consistent with accident analyses assumptions. The team evaluated pump performance and vibration trending data, to verify that design basis requirements were incorporated into test acceptance criteria. The team discussed the SW pump design, operation, and performance with engineering staff to gain an understanding of the performance history and overall component health. The team conducted walkdowns to visually inspect the SW pump and intake structure to assess the physical and material condition of the SW pump and support systems. The walkdowns verified configuration control by inspecting the installed configuration to ensure consistency with system drawings and the licensing bases. The team reviewed the traveling screen/strainer to ensure it was consistent with its design bases. The team reviewed the SW pump submergence requirements to ensure the pump was capable of fulfilling its safety function at the maximum flowrate assumed and lowest intake level. The team reviewed calculations that established voltage drop, ampacity, protection and coordination, motor brake horsepower (BHP) requirements, and short circuit ratings for the motor power supply and feeder cables to verify that design bases and assumptions were appropriately translated into design calculations. The team reviewed corrective action documents to evaluate whether there were any adverse trends associated with the pump and to assess Constellations capability to evaluate and correct problems.

c. Findings

No findings were identified.

.2.1.1 2 Safety Injection Pump A

a. Inspection Scope

The team inspected the A safety injection pump to verify that it was capable of meeting its design basis requirements. The safety injection pumps are designed to supply high pressure borated emergency core cooling water from the refueling water storage tank to the reactor vessel following a loss of coolant accident. The team reviewed the UFSAR, TS requirements, drawings, and procedures to verify that the design basis and design assumptions were appropriately translated into design documents and procedures. The team reviewed design and operational requirements with respect to pump flow rate, developed head, tested system flowrate, net-positive-suction-head (NPSH), and minimum flowrate. The team reviewed a sample of surveillance test results to verify that pump performance met the acceptance criteria and that the criteria were consistent with design basis assumptions. In addition, the team reviewed the established acceptance criteria for the pump discharge check valves to ensure the system design hydraulic modeling input assumptions were maintained. The team also reviewed emergency operating procedures to verify that selected operator actions could be accomplished and were consistent with the system design assumptions.

The team reviewed calculations that established voltage drop, ampacity, protection and coordination, motor BHP requirements, and short circuit ratings for the motor power supply and feeder cables to verify that design bases and assumptions were appropriately translated into design calculations. The team reviewed corrective action documents to evaluate whether there were any adverse trends associated with the pump and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 3 Emergency Diesel Generator A (Mechanical Review)

a. Inspection Scope

The team inspected the A EDG mechanical systems to evaluate whether they were capable of supporting the design basis function of the EDGs. The design function of the A EDG is to provide standby power to the safety-related bus when the preferred offsite power supply is not available. The team selected the engine, fuel oil, air start, lubricating oil, and jacket water cooling systems for an in-depth review. The team reviewed fuel oil consumption calculations, EDG operating procedures, EDG surveillance tests, and the TSs to verify that Constellation maintained sufficient fuel oil inventory for design basis accidents. The team also reviewed recent fuel oil, lubricating oil, and jacket water chemistry results to ensure the respective sample was within the required specifications.

The team reviewed the EDG air start capacity tests to ensure that the starting air system could deliver the required number of engine start attempts.

The team reviewed EDG performance tests to determine that the engine performance parameters, such as vibration, exhaust cylinder temperatures, and lubricating oil and fuel oil filter differential pressures were maintained within acceptable limits. The team also reviewed the cooling water design documents for the lubricating oil and jacket water coolers to determine system requirements and tube plugging limits, and reviewed heat exchanger inspection reports to ensure that heat transfer design assumptions were maintained. The team reviewed corrective action documents to evaluate whether there were any adverse trends and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 4 Residual Heat Removal Motor-Operated Valve 852B

a. Inspection Scope

The team inspected the residual heat removal (RHR) motor-operated valve (MOV) 852B to evaluate whether the valve was capable of performing its design basis function. This normally closed MOV is designed to open to provide low head safety injection water to the reactor vessel following a design basis accident. The team reviewed the UFSAR and TSs to identify the design basis requirements for the valve. The team reviewed calculations for valve stem thrust and actuator inputs to ensure that the MOV was capable of operation under the worst-case temperature, pressure, and environmental conditions. The team reviewed periodic verification MOV diagnostic test results and surveillance test procedures to verify acceptance criteria were met and consistent with the design basis and TS requirements. The team interviewed Constellation engineers to ensure recommended maintenance had been established through the PM program and design changes had been implemented satisfactorily in accordance with station procedures. The team verified that the voltage used in the valve thrust and torque limit calculation enveloped the calculated available voltage at the motor terminals under degraded voltage conditions to ensure that the voltage was sufficient for valve operation.

The control voltage drop calculations, control fuse sizing, and thermal overload sizing were reviewed to ensure the motor could support valve operation. The team reviewed plant drawings and maintenance records to access the material condition of the valve.

The team reviewed corrective action documents to evaluate whether there were any adverse trends with the MOV and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 5 Residual Heat Removal Air-Operated Valve AOV 624

a. Inspection Scope

The team inspected the RHR air-operated valve (AOV) 624, to verify that the valve was capable of performing its design basis function to control RHR flow to the vessel cold legs. This AOV is normally locked in a throttled open position to provide RHR pump run-out protection and ensure adequate pump NPSH. The team reviewed NPSH calculations, RHR flow diagrams, and solenoid schematic diagrams to verify that operation and control logic was consistent with the system design requirements found in the UFSAR. The team reviewed logic actuation testing and in-service valve stroke testing to verify that design basis stroke times were enveloped by test acceptance criteria. The team performed walkdowns of the AOV and the associated components to assess their material condition. The team interviewed system and design engineers to ensure recommended maintenance had been established through the PM program.

The team reviewed corrective action documents to evaluate whether there were any adverse trends with the AOV and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 6 Motor-Driven Auxiliary Feedwater Pump A

a. Inspection Scope

The team inspected the A motor-driven auxiliary feedwater (MDAFW) pump to verify that it was capable of meeting its design basis requirements. The auxiliary feedwater (AFW) system is designed to provide water to the steam generators (SG) upon the loss of normal feedwater supply. The team reviewed the UFSAR, drawings, the AFW design basis document (DBD), and procedures to identify the most limiting requirements for the pump. The team reviewed a sample of surveillance test results to verify that pump performance met the acceptance criteria and that the criteria were consistent with the design basis. The team also reviewed calculations for NPSH to ensure that the pump could successfully operate under the most limiting conditions. The team discussed the design, operation, and corrective maintenance of the pump with engineering staff to gain an understanding of the performance history and overall component health. The team conducted several walkdowns to visually inspect the physical/material condition of the pump and its support systems, to assess the pump capability under postulated seismic conditions, and to ensure adequate configuration control. The team reviewed a failure of the A MDAFW pump speed increaser lubricating oil pump during the inspection to ensure Constellation appropriately evaluated the condition and took adequate actions to return the pump to service.

b. Findings

No findings were identified.

.2.1.1 7 Atmospheric Relief Valve 3410

a. Inspection Scope

The team inspected the atmospheric relief valve (ARV) 3410 to evaluate whether the valve was capable of performing its design basis function. The ARV 3410 is one of two air-operated valves on the main steam header. One of the two design functions of the ARV is to perform plant cool down in the event that the steam dump valves to the condenser are unavailable. The second design function is to provide steam generator pressure relief below the setpoint of the main steam safety valves. The team reviewed calculations and engineering evaluations associated with an ARV replacement and modification of the ARV discharge piping to ensure that the new valve was capable of performing in accordance with its design. The team interviewed Constellation engineers to ensure recommended maintenance had been established through the PM program and design changes had been implemented satisfactorily in accordance with station procedures. The team conducted a walkdown of ARV 3410 and the piping leading from the discharge of the ARV up through the roof of the intermediate building to verify the discharge piping seismic restraints were in accordance with the design requirements.

The team reviewed surveillance test procedures to verify that design basis stroke times were enveloped by test acceptance criteria. The team reviewed corrective action documents to evaluate whether there were any adverse trends with the AOV and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 8 Auxiliary Feedwater Pump A Discharge Check Valve, 4000C

a. Inspection Scope

The team inspected the AFW pump A discharge check valve 4000C to evaluate whether the valve was capable of performing its design basis function. This valve is a normally closed check valve in the AFW injection line to the steam generators. The team reviewed the UFSAR, the TSs, drawings, and procedures to identify the design basis requirements of the valve and to verify that the 4000C valve has been tested in accordance with the TS requirements. The team reviewed design documentation for recent replacement and relocation of the valve, including the post maintenance testing.

The team conducted a system walkdown with, Constellation engineers, discussed the valves performance/trending, and reviewed the valves maintenance and in-service test history. The inspectors reviewed Constellations response to NRC Bulletin 88-04, Potential Safety Related Pump Loss, (issues with back flow through check valves leading to dead heading of pumps) and subsequent actions associated with AFW system check valves to verify that the design basis for the system was being maintained. The team reviewed corrective action documents to evaluate whether there were any adverse trends with the check valve and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 9 Turbine-Driven Auxiliary Feedwater Pump Steam Admission Valve 3505A

a. Inspection Scope

The team inspected the turbine-driven auxiliary feedwater pump steam admission valve 3505A to verify it was capable of performing its design function. The valve is a normally closed MOV located in the steam supply line from steam header A to the AFW pump turbine. The valves design is to automatically open upon the receipt of a start signal to the turbine-driven AFW pump. The team reviewed the control circuit diagrams, the thrust/torque calculations, and the recent testing documents to verify that the valve would function in accordance with its design requirements. The team also reviewed the engineering change package (ECP) that was developed for a replacement of the valve to verify that the appropriate design requirements were specified and met by the engineering change. The associated work orders for the replacement and the post maintenance testing were also reviewed. The team interviewed the MOV program engineer and system engineer to gain an understanding of maintenance issues and overall reliability of the valve. The team reviewed plant drawings, maintenance records, and performed a walkdown of system indications and controls located outside of containment to assess the material condition of the valve. The team reviewed corrective action documents to evaluate whether there were any adverse trends with the valve and to assess Constellations capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.2 Review of Industry Operating Experience and Generic Issues (3 samples)

The team reviewed selected OE issues for applicability at the Ginna Station. The team performed a detailed review of the OE issues listed below to evaluate whether Constellation had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.

.2.2.1 NRC Information Notice 2011-04: Contaminants and Stagnant Conditions Affecting

Stress Corrosion Cracking in Stainless Steel Piping in Pressurized Water Reactors

a. Inspection Scope

The team inspected the review performed by Constellation of NRC Information Notice (IN) 2011-04. This IN discussed recent industry Operating Experience regarding the effects of contaminants and stagnant conditions on the potential for stress corrosion cracking (SCC) in stainless steel piping in pressurized water reactors. The team reviewed the condition report associated with the IN and the corrective actions that were initiated and assigned. The team also reviewed plant records associated with in-service testing. Additionally, the team verified that appropriate changes had been performed to the applicable surveillance and walkdown procedures and conducted interviews with Constellation engineers to evaluate the effectiveness of the corrective actions taken.

b. Findings

No findings were identified.

.2.2.2 NRC Information Notice 2012-11: Age-Related Capacitor Degradation

a. Inspection Scope

The team inspected the review performed by Constellation of NRC IN 2012-11, Age-Related Capacitor Degradation. The IN was issued to inform licensees of recent problems involving age-related degradation of capacitors. The principle cause for the failed capacitors was a breakdown of the epoxy insulation in resistor/capacitor suppressors which caused equipment failures due to high current flow and heating.

The team evaluated the adequacy of Constellations evaluation of the IN by reviewing specific condition reports, results of periodic inspections of capacitors for a sample of safety-related components, capacitance test results, and thermography of electrical components. Additionally, the team reviewed the adequacy of preventive maintenance procedures and templates, vendor recommended maintenance schedules, and shelf life control procedures. The team conducted interviews with engineering personnel to evaluate the effectiveness of corrective actions taken.

b. Findings

No findings were identified.

.2.2.3 Operating Experience Smart Sample FY 2010-01 - Recent Inspection Experience for

Components Installed Beyond Vendor Recommended Service Life

a. Inspection Scope

NRC Operating Experience Smart Sample (OPESS) FY 2010-01 provided inspection guidance and inspection findings of components that: 1) failed as a result of exceeding vendor-recommended service life, or 2) failed prior to reaching their recommended service life. The team reviewed CNG-AM-1.01-2000, Scoping and Identification of Critical Components, Revision 202, which provided Constellations equipment reliability process used for identification of equipment critical to the stations safe and reliable operation including single point vulnerabilities. This process includes programs such as reliability-centered maintenance, preventive maintenance, corrective maintenance, maintenance rule, surveillance and testing, life cycle management planning, and equipment performance and condition monitoring. Additionally, the team interviewed station personnel responsible for system components aging management and associated preventive maintenance programs to evaluate the effectiveness of the programs.

b.

Findinqs No findings were identified.

4OA2 Identification and Resolution of Problems (IP 71152)

a. Inspection Scope

The team reviewed a sample of problems that Constellation identified and entered into their corrective action program. The team reviewed these issues to evaluate whether Constellation had an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions. In addition, corrective action documents written on issues identified during the inspection were reviewed to evaluate adequate problem identification and incorporation of the problem into the corrective action program. The corrective action documents that were sampled and reviewed by the team are listed in the Attachment.

b.

Findinqs No findings were identified.

4OA6 Meetings, including Exit

On August 22, 2013, the team presented the inspection results to Mr. Joseph Pacher, Site Vice President, and other members of the Constellation staff. The team verified that none of the information in this report is proprietary.

Supplemental Information ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Pacher, Vice President, Ginna

M. Philippon, Plant General Manager

M. Amos, System Engineer

R. Carey, System Engineer

D. Crowley, System Engineer

E. Durkish, Engineering Supervisor

A. Freedman, System Engineer

R. Hellems, System Engineer

J. Jackson, Licensing Supervisor

F. Klepacki, Program Engineer

J. Koshack, Senior Reactor Operator

J. Ortiz, Licensing Specialist,

B. Rapin, System Engineer

M. Smith, System Engineer

LIST OF ITEMS

Opened and Closed

05000244/2013007-01 NCV Required Voltage and Timing Criteria for Load Tap Changer Controls and Motor (1R21.2.1.1)

Opened

05000244/2013007-02 URI Adequacy of Ginnas Licensing and Design Bases for Offsite Power Calculations and Degraded Voltage Relay Time Delays (1R21.2.1.2)