IR 05000247/2012007

IR 05000247-12-007 and 05000286-12-007, on 10/15/12 - 11/09/12; Indian Point Nuclear Generating (Indian Point) Units 2 and 3; Component Design Bases Inspection

ML12356A304
Person / Time
Site:	Indian Point
Issue date:	12/21/2012
From:	Doerflein L Engineering Region 1 Branch 2
To:	Ventosa J Entergy Nuclear Operations
References
IR-12-007
Download: ML12356A304 (45)

Text

UNITED STATES NUCLEAR REGULATORY COiIMISSION

REGION I

21OO RENAISSANCE BOULEVARD, SUITE 1OO

SUBJECT:

INDIAN POINT NUCLEAR GENERATING UNITS 2 and 3 - NRC COMPONENT DESIGN BASES INSPECTION REPORT 0500024712012007 and 05004286t2012007

Dear Mr.

On November 9, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Indian Point Nuclear Generating Units 2 and 3. The enclosed inspection report documents the inspection results, which were discussed on November 9,2012, 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 Commission's rules and regulations and with the conditions of your license.

In conducting the inspection, the team examined the adequacy of selected components 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 three NRC-identified findings of very low safety significance (Green).

These findings were determined to be violations of NRC requirements. However, because of the very low safety significance and because they have been entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCV) consistent with Section 2.3.2.a of the NRC's Enforcement Policy. lf you contest any 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 DC 20555-0001; with copies to the Regional Administrator, Region l; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Senior Resident lnspectors at Indian Point Nuclear Generating Units 2 and 3.

J. Ventosa ln accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 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 NRC Public Docket Room or from the Publicly Available Records component of NRC's document system, Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.qov/readins-rm/adams.html (the Public Electronic Reading Room).

Sincerely, CiAru-"*r Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Docket No.: 50-247150-286 License No.: DPR-26/DPR-64

Enclosure:

I nspection Report 05000247 l2O12OQ7 and 05000286/2012007 w/Attachment: Supplementary Information

REGION I Docket No: 50-247t50-286 License No: DPR-26/DPR-64 Report No: 05000247 120 1 2007 a nd 05000286 l2O1 2007 Licensee: Entergy Nuclear Northeast (Entergy)

Facility: lndian Point Nuclear Generating Units 2 and 3 Location: 450 Broadway, GSB Buchanan, NY 1051 1-0249 Inspection Period: October 15 through November 9,2012 Inspectors: F. Arner, Senior Reactor Inspector, Division of Reactor Safety (DRS),

Team Leader J. Schoppy, Senior Reactor lnspector, DRS D. Kern, Senior Reactor Inspector, DRS D. Orr, Senior Reactor Inspector, DRS J. Ayala, Reactor lnspector, Division of Reactor Projects (DRP)

M. Orr, Reactor Inspector, DRS M. Yeminy, NRC Mechanical Contractor N. DellaGreca, NRC Electrical Contractor M. Singletary, Reactor Inspector (intraining)

Approved By: Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety

SUMMARY OF FINDINGS

lR 0500024712012007 and 05000286120120A7; 10115112 - 11109112; Indian Point Nuclear

Generating (lndian Point) Units 2 and 3; Component Design Bases Inspection.

The report covers the Component Design Bases Inspection conducted by a team of six NRC inspectors and two NRC contractors. Three findings of very low safety significance (Green)were identified, all of which were considered to be non-cited violations (NCV). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (lMC) 0609, "Significance Determination Process." Cross-cutting aspects associated with findings are determined using IMC 0310, "Components Within the Cross-Cutting Areas."

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

NRC-ldentified Findinqs Gornerstone: 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 lll, Design Control, because Entergy had not verified the adequacy of the design with respect to ensuring the Unit 2 480V emergency Bus 64 offsite power supply breaker amptector trip system would not inadvertently trip under accident load during degraded grid conditions. Specifically,

Entergy's evaluation did not account for the overall accuracy of the amptector long-time over-current trip system and the loop calibration procedures did not verify that the breaker would trip within the assumed trip system tolerance of t4 percent. Entergy entered the issue into their corrective action program to address the design analysis deficiency and evaluate the adequacy of the calibration procedures, and performed an operability evaluation to ensure the breaker would not inadvertently trip during anticipated accident loads.

The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 -

Mitigating Systems Screening Questions. The finding was determined to be of very low safety significance (Green) because it was a design deficiency confirmed not to result in loss of operability. This finding was not assigned a cross-cutting aspect because it was a historical design issue not indicative of current performance. Specifically, the deficiency originated in a 1993 design evaluation. (Section 1R21.2.1.1)o Green: The team identified a finding of very low safety significance (Green) involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion lll, Design Control, because Entergy had not verified the adequacy of their design with respect to the potential impact on safety-related electrical equipment in response to postulated turbine building high energy line breaks (HELBS). Specifically, the potential impact on safety-related equipment contained in the adjacent control building cable spreading room and 480V switchgear room had not been adequately evaluated. Entergy entered the issue into their corrective action program to perform an operability evaluation and correct the design deficiency and to determine the need for additional analyses or plant changes to address the HELB issue and conformance with equipment qualification design considerations.

The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 -

Mitigating Systems Screening Questions. The finding was determined to be of very low safety significance because it was a design deficiency confirmed not to result in a loss of operability. This finding was not assigned a cross-cutting aspect because it was a historical design issue not indicative of current performance. Specifically, the deficiency was associated with an analysis performed in 1973 and was not identified in a subsequent review of operating experience performed in 2000. (Section 1R21.2.1.1)

. Green: The team identified a finding of very low safety significance (Green) involving a non-cited violation of 10 CFR.Part 50, Appendix B, Criterion lll, Design Control, because Entergy had not verified the adequacy of the existing design analyses for internal recirculation pump net-positive-suction-head (NPSH) margin and vapor containment strainer allowable head loss determinations. Specifically, the recirculation pump flow system hydraulic modeling assumption relative to zero leakage through an idle recirculation pump check valve was not verified or consistent with the existing test method which could allow significant backflow with the established pump and check valve test acceptance criteria. Entergy entered the issue into their corrective action program to evaluate and resolve the design deficiency, and performed an operability evaluation to ensure there was adequate NPSH margin.

The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely atfected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 -

Mitigating Systems Screening Questions. The finding was determined to be of very low safety significance because it was a design deficiency confirmed not to result in a loss of operability. This finding was not assigned a cross-cutting aspect because it was a historical design issue not indicative of current performance. Specifically, the performance deficiency had occurred outside of the nominal three year period for evaluating present performance as defined in IMC 0612. (Section 1R21.2.1.2)

Other Findinss None ill

REPORT DETAILS

1. REACTOR SAFEry

Cornerstones: Initiating Events, Mitigating Systems, and Barrier lntegrity

==1R21 Component Desiqn Bases Inspection (lP 71111.21)

.1 Inspection Sample Selection Process

==

The team selected risk significant components for review using information contained in the Indian Point Nuclear Generating (lndian Point) Units 2 and 3 Probabilistic Risk Assessments (PRA) and the U.S. Nuclear Regulatory Commission's (NRC) Standardized Plant Analysis Risk (SPAR) models for Indian Point Units 2 and 3. Additionally, the team referenced the Risk-lnformed Inspection Notebooks for lndian Point Units 2 and 3 (Revision 2.1a) 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 components selected were associated with both safety-related and non-safety related systems, and included a variety of components such as pumps, transformers, diesel engines, batteries, 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 (CDBI) reports and excluded the majority of those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 23 components and three operating experience (OE) items. The team selected the Unit 2 containment pressure relief valves and a Unit 3 containment recirculation spray valve to review for large early release frequency (LERF) implications.

The team's evaluation of possible low design margin 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 (aX1) status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry OE.

Finally, consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins.

The inspection performed by the team was conducted as outlined in NRC Inspection Procedure (lP) 71 111.21. 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 design basis, licensing basis, and risk-informed beyond design basis requirements. Summaries of the reviews performed for each component and OE sample are discussed in the subsequent sections of this report. Documents reviewed for this inspection are listed in the Attachment.

.2.1.1 Unit 2 480 Volt Bus 5A

a. Inspection Scope

The team inspected the Unit 2 480V Bus 5A to verify it was capable of performing its design function. Specifically, the team reviewed load flow calculations, short circuit calculations, and the trip setting of the supply circuit breaker amptector to evaluate the adequacy of the bus and breakers to carry anticipated loads under limiting conditions and to withstand and interrupt maximum potential faults. The review included electrical protection settings, equipment ratings, prevention of spurious tripping, upstream-downstream coordination, and capability of protective devices to guard against low magnitude faults. The amptector setting of the supply circuit breaker for the Unit 2 480V Bus 64 was also reviewed due to its low margin between accident load current and the established setpoint. The team reviewed historical voltage levels of the offsite system, capability of the transformer automatic load tap changer (LTC), voltage drop calculations, and the degraded voltage relay settings to confirm that adequate voltage was available at the terminals of the safety-related loads under worst case accident conditions.

The team also reviewed breaker logic and controlwiring diagrams to ensure breaker operation was consistent with the system design requirements. This included verifying that adequate voltage was available to the control circuits for the proper closing and tripping of breakers, and that actuation of the degraded voltage and loss-of-voltage relays initiated the emergency diesel generator starting sequence. The team reviewed maintenance and testing procedures to confirm that the maintenance and testing of breakers and bus were in accordance with industry standards, manufacturer recommendations, and the technical specification requirements. The team also reviewed the system health report, the results of recent maintenance and test activities, and the resolution of selected condition reports to ensure that the bus and breakers were maintained in an acceptable operating condition. The team conducted a walkdown of the bus to evaluate the configuration and material condition of the equipment.

In addition, the team evaluated operator actions to recognize and mitigate a circulating water (CW) expansion joint failure in the Unit 2 turbine building to preclude flooding impact to the Unit 2 1E 480V safety buses. Specifically, operator critical tasks included:

o Recognize condition o Direct response in accordance with alarm response procedures (ARP)

.

Confirm flooding

.

Mitigate flooding by opening roll-up doors in turbine building

.

Determine cause o lsolate source (trip respective CW pump)

The team reviewed the associated ARPs, interviewed operators, and conducted a walkthrough of time-critical flood mitigation strategies to verify that the procedures and actions were adequate, reasonable to mitigate the postulated rupture, and consistent with licensing basis documents. In addition, the team independently walked down the Unit 2 480V switchgear room and lower elevations of the Unit 1 and Unit 2 turbine buildings to assess the material condition of the associated structures, systems and components (SSC) with particular focus on potential high volume internal flood sources (including the CW expansion joints). The team independently assessed procedure quality, flood float instrument material condition and periodic testing, and Entergy's configuration control of internal flood design features.

b.1 Findinos lntroduction: The team identified a finding of very low safety significance involving a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion lll, Design Control, because Entergy had not verified the adequacy of the design with respect to ensuring the Unit 2 480V emergency Bus 6A offsite power supply breaker amptector trip system would not inadvertently trip under accident load during degraded grid conditions. Specifically, Entergy's evaluation did not account for the overall accuracy of the amptector long-time over-current trip system and the loop calibration procedures did not verify that the breaker would trip within the assumed trip system tolerance of t4 percent.

Description:

Calculation FEX-00143, Revision 1,lP2 Load FlowAnalysis of the Electrical Distribution System, evaluated the voltage drop and bus loading on all four safety-related buses under various plant operating and accident conditions taking into consideration historical maximum and minimum grid voltage levels. While reviewing this calculation to assess design capabilities of Bus 5A, the team noted that with the grid at the minimum postulated voltage of 133.2 kV, a postulated safety injection (Sl) signalwould result in the load on Bus 64 of 3455.7 amperes (A) with the transformer automatic LTC operating.

The calculation also indicated a load of 3584.244 with the LTC not operating and the bus voltage at the degraded voltage relay setting. Additionally, Table 8.7-2 indicated that following the Sl and manual loading with the LTC operating, the total load on Bus 6,4 was 3525.78A' The 480V switchgear is equipped with Westinghouse DB-75 breakers with amptectors that can be adjusted to ensure coordination with other upstream and downstream circuit protectors. For the Bus 6A offsite power supply breaker, the licensee had established a trip setting of 37504 as documented within a 1993 engineering calculation, SGX-00018-00, Indian Point 2 - Station Service Transformer 6, 480 Volt Circuit Breaker Settings. This setting, the maximum setting for the component, was required because the licensee had determined that the calculated loads under postulated degraded voltage conditions could potentially result in the supply breaker tripping and preventing the automatic loading of the associated emergency diesel generator. Additionally, because the published trip accuracy of the amptector was t10 percent of the trip setting, the licensee discussed the component tolerance with the manufacturer and determined that the amptector had a repeatability of +2 percent if calibrated using primary or secondary current injection. Therefore, in calculation SGX-00018-00, the licensee conservatively assumed a repeatability of t4 percent and prepared procedures to calibrate the amptector accordingly. In the procedure the licensee specified the injection of secondary current into the amptector and the setting of its actuation at 6.3A, corresponding to 3780A (3750A nominal). The procedure also established an acceptable as-found minimum actuation point of 6,4, corresponding to 3600A which aligned with the assumed

-4 percent tolerance requirement. This setting was established with the intent to provide sufficient margin to prevent an advertent trip of the circuit breaker and lockout of the bus with the calculated accident loads during degraded voltage design conditions.

The team determined during a review of existing surveillance/calibration procedures that Entergy, by injecting the secondary current directly into the amptector, was not taking into account the accuracy of the current transformer and had not addressed the accuracy of the entire loop. A 1988 vendor letter had established that repeatability of the amptector system would be within t2 percent with either the primary or the secondary current injection method, i.e., either through the current transformer or directly into the amptector. However, the vendor cautioned that the use of the primary and secondary current test methods at equivalent currents produces different time results because of the influence of the sensor (the current transformer). The vendor indicated that both methods fall within the trip curve's band of accuracy. The team noted that because the licensee had not taken into account the accuracy of the sensors and had not developed equipment specific trip curves, the only curves that could be relied upon were the ones developed by the manufacturer with an accuracy of t10 percent.

A-1 of FEX-00141-00, lP2 Amptector Setting Verification, Sensor and Tolerances, was initiated in the 2002 timeframe and summarized the basis for each of the 480V switchgear breaker amptector settings. This analysis had recognized and determined that loop accuracy including the sensor was *10.0 percent. Specifically, the evaluation indicated that if the amptector pickup value was set by primary current injection, then the as-left accuracy of the overall system would be equal to the accuracy of the primary injection maintenance and test equipment (M&TE) and that this calibration method would nullify or calibrate out the etfect of the sensor. The team noted that the method suggested by the calculation was not addressed in the calibration procedure.

Additionally the team observed that although the licensee does conduct tests using primary injection to evaluate the actuation point of the breaker, the current injected (12200A) is very high and the response accepted (30-100 seconds) is outside the t4 percent desired tolerance as well as the t10 percent specified by the circuit breaker manufacturer. The team determined that based on the 2002 calculation and existing test procedure methods the t10 percent overall loop tolerance assumption was appropriate.

The team concluded that the t4 percent accuracy assumed in previous analyses for margin determination to prevent inadvertent breaker trip during Sl conditions had not been adequately justified.

In response to the team's concern, Entergy performed an operability evaluation of their margin based on a more recent model of the electdcal system loads using an ETAP program. Preliminary results indicated a maximum bus loading of 3355.5A at the degraded grid design conditions indicating that the supply circuit breaker would not inadvertently trip during anticipated loads even if the circuit breaker operated at the lowest point of the trip curve band. Entergy initiated a condition report (CR-lP2-2012-06683) to address the design analysis deficiency and formalize their evaluation including determining if calibration procedures required revision. The team reviewed Entergy's basis for operability and determined that it was reasonable.

Analvsis: The team determined that the failure to verify the adequacy of the design with respect to ensuring the amptector trip system for the offsite power supply breaker for the Unit 2 480V emergency Bus 64 would not inadvertently trip during worst case loss-of-coolant (LOCA) load current under degraded grid conditions was a performance deficiency. The performance deficiency was determined to be more than minor because it was similar to Inspection Manual Chapter (lMC) 0612, Appendix E, Examples of Minor lssues, Example 3.j, in that the failure to address overall loop amptector trip system accuracy resulted in reasonable doubt that margin existed to prevent inadvertent tripping of the 64 Bus supply breaker during accident loading under degraded voltage conditions.

In addition, the performance deficiency was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 -

Mitigating Systems Screening Questions, the team screened the finding and determined that it was of very low safety significance (Green) because it was a design deficiency confirmed not to result in loss of operability. This finding was not assigned a cross-cutting aspect because it was a historical design issue not indicative of current performance. Specifically, the deficiency originated in a 1993 design evaluation.

Enforcement:

10 CFR Part 50, Appendix B, Criterion lll, 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 November 9, 2012, Entergy had not verified the adequacy of the design with respect to ensuring the amptector trip system for the offsite power supply breaker for the Unit 2 480V emergency Bus 64 would not inadvertently trip during worst case LOCA load current under degraded grid conditions. Specifically, the assumed t4 percent amptector trip curve's band of accuracy within calculation SGX-00018-00 had not taken into account the instrument loop sensor error and existing calibration surveillance procedures had not accounted for the potential sensor error.

However, because this violation was of very low safety significance, and because it was entered in the licensee's corrective action program (CAP) as CR-lP2-2012-06683, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000247 12012007 -01, Inadequate Design Verification that Bus 6A supply breaker amptector would not inadvertently trip and lockout bus during degraded grid accident Sl load current)b.2 Findinos

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion lll, Design Control, because Entergy had not verified the adequacy of their design with respect to the potential impact on safety-related electrical equipment in response to postulated turbine building (TB) high energy line breaks (HELB). Specifically, the potential impact on safety-related equipment contained in the adjacent control building cable spreading room and 480V switchgear room had not been adequately evaluated.

Description:

The team noted that normal ventilation for the safety-related switchgear rooms in both units consisted of ventilation systems that would be loaded onto safety related buses therefore ensuring that ventilation was maintained under loss-of-offsite power (LOOP) conditions. Additionally, the team determined that although the switchgear was located in the control building, the ventilation system took suction from the turbine building and therefore an interface existed between the two building environments. The team determined that a postulated HELB in the turbine building would result in the hot and high humidity HELB environment potentially communicating with the safety-related switchgear room through the ventilation system. The Unit 2 control building switchgear room ventilation is designed to draw suction from the turbine building. The flowrate is dependent on the rooms'temperature and can be as high as 60,000 cubic foot per minute (cfm). The Unit 3 switchgear room ventilation draws in up to 50,000 cfm, taking suction from the turbine building, but hs room temperature rises to a nominal 93 degrees Fahrenheit, louvers to outside air also open and the suction would consist of a mix of outside and turbine building air.

The licensee had originally performed HELB analyses studies back in the 1973 timeframe and had responded to requests from the Atomic Energy Commission (AEC)regarding the affect of potential HELB scenarios. The licensee had conducted evaluations to determine the etfects of a postulated break in a main steam or feedwater line on the auxiliary feedwater system and on the ability to bring the plant to a safe shutdown condition. The team noted that additional evaluations were completed to determine the effects of postulated breaks in other areas of the plant outside containment, including postulated breaks in the turbine building. In an April 9, 1973, letter to the AEC regarding Unit 2, the licensee recognized and documented that the AEC practice was to assume that any incident which causes a plant trip would cause a loss of normal alternating current (AC) offsite power as well. Therefore, the licensee determined that several modifications were required in analyzing other postulated breaks such as a steamline break in the auxiliary feedwater (AFW) pump room to ensure that safe shutdown capability could be maintained. This resulted in the implementation of several modifications to the AFW system to protect the design requirement of safe shutdown capability. Part 2 of the 1973 design evaluation letter consisted of the review of postulated breaks in the turbine building. Because the turbine buildings adjoin the control building, high energy lines in the turbine building were investigated for the potential etfects on the control building. The evaluations determined that the volume of the turbine building was so great and the ventilation flow so large (approximately 1.1 million cfm) that temperature and pressure buildup in the building would be small. Additionally, it was concluded that the doors to the control buildings are kept closed and therefore any steam leak into the control building would be noticed by the operators who would trip the plant and stop the flow of steam.

The team determined that this evaluation was flawed because it had not recognized or evaluated the fact that a HELB in the turbine building could have a direct interface with the control building essential switchgear room because of the design of the ventilation system. The team was also concerned that there was a qualitative reliance on a significant ventilation flowrate (1.1 million cfm) from the non-safety related turbine building exhaust fans. The team noted that the crediting of non-safety related ventilation was also not consistent with their previous assumption of loss-of-offsite power during these postulated HELB events which result in unit trips. Additionally, the team noted that offsite power switchgear was located in the turbine building where the postulated break could occur but there was no evaluation with respect to survivability of the offsite power source. The team reviewed relative humidity and temperature design limits for safety related equipment located in the 480V switchgear room and was concerned that equipment relative humidity and temperature design ratings could be exceeded for postulated HELB conditions, in addition to the potential for condensation affecting equipment operation. The team determined that the switchgear ventilation systems were not equipped with steam isolation devices that were specifically designed and evaluated for their capability to isolate the room given the spectrum of potential turbine building environmental conditions. The team noted in the review of this issue that the licensee had a previous missed opportunity to identify and evaluate this condition during their review of NRC lnformation Notice 2000-20, Potential Loss of Redundant Safety Related Equipment because of the Lack of High Energy Line Break Barriers. The team determined that this design issue affected both units.

Entergy entered the issue into their corrective action system and performed an immediate reasonable expectation of operability for both units. Entergy's review recognized that the ventilation interface had not been previously evaluated in their design, including the potential effect on the cable spreading rooms which also took a suction from the turbine building. An initial engineering model analysis for a main steam line break (MSLB) in the turbine building coincident with a single failure of one main steam isolation valve (MSIV) to close was run to determine worst case conditions and potential etfect on safety-related equipment. lnitial and followup operability reviews determined that control building ventilation fire dampers would close due to the 165 degree Fahrenheit melting point of their fusible links for a spectrum of postulated break sizes given the expected temperature response in the building. Entergy determined that this would effectively isolate the control building and its safety-related equipment. This review also determined that the dampers could function against the expected maximum differential pressures. Additionally, the total water content was calculated assuming all of the steam in the area of interest was condensed following closure of the fire dampers to evaluate the effect of any potential condensation. The engineering model supported the conclusion that safety-related equipment required for safe shutdown would reasonably be expected to remain functional. Entergy initiated a followup action to determine the need for additional analyses or plant changes to address the HELB issue in the long term including addressing conformance with equipment qualification design considerations.

The team reviewed Entergy's basis for operability and determined that it was reasonable.

Analvsis: The team determined that the failure to verify the adequacy of the design with respect to the potential impact on safety-related electrical equipment in response to postulated turbine building HELBs was a performance deficiency. Specifically, the potential impact on safety-related equipment contained in the adjacent cabld spreading room and 480V switchgear room had not been adequately evaluated. This performance deficiency was more than minor because it was similar to IMC 0612, Appendix E, Examples of Minor lssues, Example 3.j, in that, the design analysis deficiency resulted in a condition where the team had reasonable doubt regarding the operability of potentially affected safety-related equipment in the switchgear rooms. ln addition, the performance deficiency was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, the team screened the finding and determined that it was of very low safety significance (Green) because it was a design deficiency confirmed not to result in loss of operability. The finding was not assigned a cross-cutting aspect because it was a historical design issue not indicative of current performance. Specifically, the deficiency was associated with an analysis performed in 1973 and was not identified in a subsequent review of operating experience performed in 2000.

Enforcement:

10 CFR Part 50, Appendix B, Criterion lll, Design Control, requires, in part, that design control measures provide for verifying or checking the adequacy of design. Contrary to the above, as of October 18, 2012, measures had not been established to verify and ensure that required safety-related equipment would perform their safety functions following a postulated turbine building HELB. Specifically, for both units, the 1973 HELB design analyses had not recognized and evaluated the interface between control building ventilation systems and the turbine building, and had non-conservatively credited the non-safety related turbine building ventilation system in evaluating the design adequacy. Because this violation is of very low safety significance and has been entered into Entergy's corrective action program (CR-lP2-2012-06255 and CR-lP3-2012-03262), this violation is being treated as a non-cited violation consistent with Section2.3.2 of the NRC Enforcement Policy. (NCV 0500024712012007-02and 05000286/2012007-02, Inadequate Turbine Building HELB evaluation for effect on Safety Related Equipment)

.2.1.2 Recirculation Pump

a. Inspection Scope

The team inspected the 21 recirculation pump to verify that it was capable of meeting its design basis requirements. The internal recirculation pump is designed to supply sump water in the containment to the reactor coolant system (RCS) and to the containment spray headers via the residual heat removal (RHR) system during the recirculation phase of a loss-of-coolant accident. The team reviewed the updated final safety analysis report (UFSAR), technical specification (TS) requirements, 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, pressure losses through the containment sump screen, 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. This review included the adequacy of the pump head capacity curve for in-service testing (lST) as well as the required NPSH curve. 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 reviewed design analyses to ensure the pump was protected from the formation of air vortexes and the adequacy of the water supply from the containment sump to support NPSH evaluations. 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 motor feeder ampacity, short circuit capability, breaker amptector setting, and breaker coordination studies to assess the adequacy of the circuit protection under normal and faulted conditions and to ensure that trip setpoints would not permit the feeder breaker to trip during pump motor highest loading conditions. The calculated available motor voltage was reviewed to confirm the availability and capability of the pump to perform its safety function under the most limiting conditions. The team reviewed motor controlwiring diagrams to determine compliance with system operation requirements and evaluated the electrical separation to ensure that the redundancy of safety divisions was not compromised. Finally, the team reviewed a sample of associated condition reports (CRs), and the latest system health report to determine if there were any adverse operating trends and to ensure Entergy adequately identified and addressed deficiencies.

b. Findinqs lntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion lll, Design Control, because Entergy had not verified the adequacy of the existing design analyses for pump NPSH margin and vapor containment strainer allowable head loss determinations. Specifically, the recirculation pump flow system hydraulic modeling assumption relative to zero leakage through an idle recirculation pump check valve was not verified or consistent with the existing test method which could allow significant backflow with the established pump and check valve test acceptance criteria.

Description:

The team noted that the most limiting flow conditions for a single recirculation pump occurs when the design condition exists where only one internal recirculation pump is operating supplying flow to the vessel and spray headers. The accident system flowpath is not available when performing system full flow testing of the pumps due to the design of the internal recirculation pump system taking suction from the vapor containment sump. Therefore, to ensure the adequacy of post accident flowrate assumptions such as reactor vessel decay heat removal and spray, vendor hydraulic flow models are used in combination with system testing, to verify the adequacy of the design of the system. These models serve to verify accident flowrates can be achieved but also generate critical design inputs such as maximum flowrates which must be analyzed to ensure NPSH margins can be maintained. During the review of calculation lP-CALC-06-00231, Rev. 1, lP U2 Sl Recirculation (LHSI & HHSI)

Performance for Containment Sump Program, the team reviewed the model assumptions for the worst-case single recirculation pump operating condition including various postulated alignments of the system. The team noted that the most conservative case was determined to be one pump operating supplying one RHR heat exchanger and containment spray. The team reviewed the emergency operating procedure (EOP) for recirculation operation, 2-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 7, and determined that the alignment credited in the evaluation of NPSH and strainer head loss was consistent with procedural direction. However, the team noted that the hydraulic models developed and used by the vendor for NPSH and strainer head allowance evaluations did not account for any potential backleakage through an idle recirculation pump discharge check valve.

The team noted that the pump discharge check valves 886,4 (21 recirculation pump) and 8868 (22 recirculation pump) have an open safety function to supply recirculation flow to the reactor vessel and containment spray and a closed safety function to prevent backleakage through an idle pump. The team determined that the surveillance test for the pumps, 2-PT-R016, Recirculation Pumps, Rev. 22, tests the check valve close function by verifying no counter-rotation of the idle pump. The team questioned what kind of leakrate (i.e. backflow) would be required to observe this counter-rotation given the size and inertia of the double suction pumps. The team noted that this flowrate had not been established prior to the inspection. Entergy contacted the pump manufacturer and determined that it would take a nominal flowrate of 900 gpm for any counter-rotation to occur. The team noted that the last test performed for the 21 recirculation pump had shown a 10 foot reduction in head below the vendor curve and questioned if a potential backleakage path could exist through the idle pump check valve which had not been recognized. Additionally, the team was concerned that if backleakage existed which had not been accounted for in hydraulic models, the pump maximum flowrate may increase affecting NPSH margin. The team noted the existing calculated margin for the 21 pump was 0.52 feet. For Unit 3, the team noted that existing analysis showed 0.01 feet NPSH margin. The team reviewed the pump surveillance test method to determine the highest backleakage that potentially could exist while still satisfying the established test acceptance criteria for pump performance. The team noted that if there was undetected backleakage through the idle pump (i.e. there is no flow indication in line to idle pump)that the pump head would decrease. A review of acceptable lower limit pump head performance for a given flowrate showed that a nominal 450 gpm backleakage could exist with the pump still satisfying the lower limits of in-service test acceptance criteria.

The team determined that the existing pump surveillance test did not verify check valve leak tightness and did not quantify any potential backleakage other than a reverse-rotation check. This was inconsistent with and did not support established hydraulic flow models for NPSH evaluations. The team noted this issue was applicable to both units.

Entergy entered the issue into their corrective action system and performed an immediate reasonable expectation of operability for both units. Entergy determined that based on additional NPSH available margin in the calculation of actual expected containment water level, the latest pump test data of where the pumps were operating relative to the vendor curve, limited system operating and wear time on the check valves, and historical check valve inspections, that there was reasonable assurance that if check valve leakage existed, sufficient margin existed within the existing NPSH evaluations to support operability. The team reviewed Entergy's basis for operability and determined that the additional margin identified bounded the worst case calculated potential backleakage given the most recent test performance data for both unit's recirculation pumps.

Analvsis: The team determined that the failure to verify the adequacy of the design with respect to the adequacy of the existing design analyses for pump NPSH margin and strainer allowable head loss determinations was a performance deficiency. Specifically, the recirculation pump flow system hydraulic modeling assumption relative to zero leakage through an idle recirculation pump check valve was not verified or consistent with the existing test method which could allow significant backflow with the established pump and check valve test acceptance criteria. This performance deficiency was more than minor because it was similar to IMC 0612, Appendix E, Examples of Minor lssues, Example 3.j, in that, the design analysis deficiency resulted in a condition where the team had reasonable doubt of operability with respect to the maintenance of existing NPSH design margin given that the amount of bypass leakage allowed for during testing was not consistent with system hydraulic design assumptions. In addition, the performance deficiency was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, the team screened the finding and determined that it was of very low safety significance (Green) because it was a design deficiency confirmed not to result in loss of operability. The finding was not assigned a cross-cutting aspect because it was a historical design issue not indicative of current performance. Specifically, the performance deficiency had occurred outside of the nominal three year period for evaluating present performance as defined in IMC 0612.

Enforcement:

10 CFR Part 50, Appendix B, Criterion lll, Design Control, requires, in part, that design control measures provide for verifying or checking the adequacy of design. Contrary to the above, as of November 8, 2012, measures had not been established to verify and ensure the adequacy of the design analysis for recirculation pump NPSH and strainer allowable head loss determinations. Specifically, the recirculation pump flow system hydraulic modeling assumption relative to zero leakage through an idle recirculation pump check valve was not verified or consistent with the existing test method which could allow significant backflow with the established pump and check valve test acceptance criteria. Because this violation is of very low safety significance and has been entered into Entergy's corrective action program (CR-lP2-2012-06646 and CR-lP3-2012-03575), this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000247t2012O07-03 and 05000286/2012007-03, Inadequate Verification of Design Analyses for Recirculation Pump NPSH)

.2.1 ,3 Component Coolinq Water Pump 23

a.

lnspection Scope The team inspected the 23 component cooling water (CCW) pump 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, the CCW 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 statf to gain an understanding of the performance history and overall component health.

The team reviewed motor feeder ampacity, short circuit capability, breaker amptector setting, and breaker coordination studies to assess the adequacy of the circuit protection under normal and faulted conditions and to ensure that trip setpoints would not permit the feeder breaker to trip during pump motor highest loading conditions. The team reviewed the calculated available motor voltage to confirm the availability and capability of the pump to perform its safety function under the most limiting conditions. The team reviewed motor control wiring diagrams to determine compliance with system operation requirements and evaluated the electrical separation to ensure that the redundancy of safety divisions was not compromised. The team conducted several detailed walkdowns to visually inspect the physical/material condition of the pump and its support systems, to assess potential seismic issues, and to ensure adequate configuration control. The team also reviewed the maintenance and operating history of the 23 CCW pump, associated corrective action documents(CRs), the latest system health report, and surveillance test results to determine if there were any adverse operating trends and to ensure that Entergy adequately identified and addressed deficiencies.

b.

Findinos No findings were identified.

.2.1.4 Emerqencv Diesel Generators 21 and 33 (Mechanical Review) (2 samples)

a. Inspection Scope

The team inspected the 21 and 33 emergency diesel generator (EDG) mechanical systems to verify that they were capable of supporting the design basis function of the EDGs. The design function of the 21 and 33 EDG is to provide standby power to their respective unit safety-related 480V Bus 5A when the preferred power supply is not available. The team selected the EDG engine, fuel oil system, air start system, lube oil system, and jacket water cooling system for an in-depth review. The team reviewed fuel oil consumption calculations, the EDG operating procedures, EDG surveillance tests, and the TSs to verify that Entergy maintained sufficient fuet oil inventory for design bases accidents. The team also reviewed recent fuel oil, lube oil, and jacket water chemistry results to ensure that 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 a risk-informed sampte of EDG control and protective relay preventive maintenance (PM) activities and calibrations to verify that the EDGs would operate reliably and were not subject to spurious trips. The team reviewed various EDG performance tests to determine whether engine performance parameters, such as vibration, exhaust cylinder temperatures, and lube oil and fuel oil filter differential pressures were maintained within the acceptance criteria. The team reviewed the EDG vendor manual, EDG surveillance tests, and PM activities for the lube oil and fuel oil filters to ensure that Entergy replaced the filters prior to any adverse impact on engine operation. The team observed maintenance tasks including the cleaning of the tube side of the 21 EDG lube oil (LO) and jacket water (JW) coolers. The team also reviewed cooling water design documents for the LO and JW coolers to determine system requirements and tube plugging limits, and reviewed recent heat exchanger inspection reports to ensure that heat transfer design assumptions were maintained. The team reviewed corrective action documents and the latest system health reports, and interviewed the system engineer to determine whether there were any adverse operating trends or existing issues affecting engine reliability. The team also conducted several detailed walkdowns of the EDGs and their support systems (including control room instrumentation) to visually inspect the material condition, to assess the operating environment and potential hazards, and to ensure adequate configuration control.

b.

Findinss No findings were identified.

.2.1.5 Emerqencv Diesel Generators 21 and 33 (Electrical Review) (2 samples)

a. Inspection Scope

The team inspected the 21 and 33 EDGs to verify they were capable of meeting their electrical system design and licensing bases requirements. Specific components of each EDG reviewed included its protective relays, 480V output breaker, exciter, and generator.

The team reviewed calculations, operating procedures, surveillance testing results, preventive maintenance records, and relay calibrations to ensure that the EDGs were operated within their ratings and were capable of operating under all design basis conditions. The team reviewed the adequacy of the EDGs to support their associated 480V safety buses and ensured that surveillance testing adequately verified that the EDGs operated at loads consistent with the worst case design basis load profile. Entergy engineers and senior reactor operators were interviewed regarding the design, operation, testing, and maintenance of the diesel generator. The team performed a walkdown of the diesel generator and support systems to assess the material condition of the equipment. Finally, a sample of CRs was reviewed to ensure Entergy was identifying and properly correcting deficiencies associated with the EDGs.

b.

Findinss No findings were identified.

.2.1.6 Service Water Pump 34

a. Inspection Scope

The team inspected the 34 service water (SW) to verify that it was capable of performing its design basis function. The Unit 3lSW system supplies cooling water from the Hudson River, the ultimate heat sink, to components both in the primary portion and the secondary portion of the plant d{ring normal operation and under accident conditions, and discharges back to the iiver. The team reviewed applicable portions of the UFSAR, the SW system DBD, anp drawings to identify the design basis requirements for the pump. The team reviewed calculations and SW system hydraulic analyses to assess available pump NPPH and determine required system flows. The team reviewed the SW pump IST re$ults and system flow verification test results to verify acceptance criteria were met an{ that the acceptance criteria were consistent with the design basis assumptions.

, the team reviewed pump data trends of vibration, differential pressure and flowlrate test results to verify acceptance criteria were met and that Entergy appropriately and evaluated adverse trends.

The team also verified that design requirements pnd operational limits were properly translated into operating instructions and alarm rBsponse procedures. The team inspected the 34 SW pump motor to verify it wa$ capable of meeting the pump power requirements. The team reviewed motor data, protective relay setpoint data, electrical coordination curves, and power calcu to verify that the motor would reliably operate under worst case conditions and support pump design requirements. In addition, the team performed walkdowns of the $W pump and strainer areas (including intake and control room instrumentation panels), interviewed Entergy engineers, and reviewed the latest system health report and CR$ to assess the current material condition and configuration control.

b.

Findinos No findings were identified.

.2.1.7 Safetv Iniection Pump

a. Inspection Scope

The team inspected the 32 Sl pump to verify it was capable of performing its design basis function. The Sl pumps are an integral of the emergency core cooling systems (EGCS) designed to provide adequate cooling under plant accident conditions. The team reviewed applicable s of the UFSAR, the Sl system DBD, and drawings to identify the design basis requi for the pump. The team reviewed design calculations to assess available pump H and determine required system flows. The team reviewed pump IST results and flow verification test results to verify acceptance criteria were met and bounded the system flow requirements. The team reviewed pump data trends for vibration to ensure equipment performance was being maintained within acceptable vibration limits. The team also reviewed Sl pump and motor cooling systems and Sl pump minimum flow requirements to assess the ability of the Sl pump to operate under design basis conditions. In addition, the team reviewed work orders and corrective action documents to identify failures or nonconforming issues, and to ensure that Entergy appropriately identified, evaluated, and corrected deficiencies. The team performed a review of the EOPs associated with post-accident pump operation to ensure that the 32 Sl pump could perform as required under postulated accident conditions. Additionally, the team inspected the 32 Sl pump motor to verify it was capable of meeting the pump power requirements. The team reviewed motor nameplate data, protective relay setpoint data, electrical coordination curves, and power calculations to determine that the motor would reliably operate under worst case conditions and support pump requirements. Finally, the team conducted several walkdowns of the 32 Sl pump and motor, CCW cooling system, and associated Sl piping to assess Entergy's configuration control, the material condition, operating environment, and potential external hazards.

b.

Findinqs No findings were identified.

.2.1.8 Auxiliarv Feedwater Pumps 23 and 33 (2 samples)

a. Inspection Scope

The team inspected the 23 and 33 AFW pumps to verify they were capable of meeting their design bases requirements. The AFW pumps were designed to supply the steam generators for their respective unit with high pressure feedwater to maintain water inventory for RCS heat removal by secondary side steam release in the event the main feedwater system is unavailable. The team reviewed the UFSAR, TS requirements, 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, NPSH, and minimum flowrates. 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. This review included the adequacy of the pump baseline head capacity curve for IST as well as the required NPSH curve. The team reviewed the test results associated with the pump discharge check valves and main feedwater check valves to ensure that reverse backleakage was accounted for in the design. The team reviewed design analyses to ensure the pump was protected from the formation of air vortexes and to evaluate the adequacy of the water supply from the suction sources (condensate storage tank and city water).

The team reviewed EOPs to verify that selected operator actions could be accomplished and were consistent with the system design assumptions. The team reviewed motor/pump performance curves to ensure that the electrical load was correctly translated in the bus loading calculations. The team reviewed short circuit capability, breaker amptector settings, and breaker coordination studies to ensure the adequacy of the circuit protection under normal and faulted conditions, and to ensure that trip setpoints would not permit the feeder breaker to trip during pump motor highest load conditions. The team reviewed motor voltage calculations to ensure the capability of the pumps to perform their safety function under the most limiting conditions. Finally, the team conducted several walkdowns of the 23 and 33 AFW pump and motors to assess Entergy's configuration control, the material condition, operating environment, and potential external hazards.

b.

Findinos No findings were identified.

.2.1.9 Unit 2 - 125V DC Power Panel2l

a.

lnspection Scope The team reviewed the design and operation of the battery bus and associated direct current (DC) power panel to verify that it was capable of performing its design basis function. The 21 power panel provides the primary source of DC power to safeguards equipment and logic circuitry at Unit 2. The review verified that the bus loading was within the design rating of the equipment and that the equipment rating exceeded the maximum calculated short circuit faults. Additionally, the team reviewed protective coordination studies to confirm that selective coordination existed between supply fuses and load protective devices to ensure that equipment was adequately protected and faulted conditions were isolated without unnecessary loss of equipment. The team interviewed Entergy engineers, and reviewed the latest system health report and maintenance activities related to molded case circuit breakers to verify that the bus components were adequately maintained and that the circuit breakers did not exceed the service qualified life. Finally, the team conducted field walkdowns to assess the material condition of the power panel components and to verify that equipment alignment, nameplate data, and breaker positions were consistent with design drawings.

b.

Findinqs No findings were identified.

.2.1.1 0 Unit 2 Station Service Transformer 6

a. Inspection Scope

The team inspected the Unit 2 station service transformer (SST) to verify that it was capable of meeting its design basis requirements. The SST 6 is designed to provide the preferred offsite power source to 480V Bus 6A. The team reviewed transformer protective relaying to determine 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 PM program and design changes had been satisfactorily implemented. Additionally, the team reviewed completed work orders and CRs to determine whether there were any adverse equipment operating trends.

b.

Findinqs No findings were identified.

.2.1.1 1Unit 3 Containment Recirculation Sprav lsolation Valve 8898

lnspection Scope The team inspected the Unit 3 containment recirculation spray isolation motor operated valve (MOV) 8898 to determine if the valve was capable of performing its design basis function. The MOV 8898 provides isolation between the residual heat removal (RHR)system low head safety injection (LHSI) and the containment spray headers. The valve opens during the recirculation phase of an accident to provide cooling to the containment atmosphere, and needs to close to restore normal recirculation flow following containment spray termination. The team reviewed the UFSAR, TSs, and DBD 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 differential pressure conditions. The team reviewed surveillance test procedures to verify that design basis stroke times were enveloped by test acceptance criteria. The team interviewed Entergy 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 limits 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. Finally, the team reviewed a sample of CRs to identify failures or adverse conditions and to determine whether deficiencies were being identified and properly addressed.

b.

Findinqs No findings were identified.

.2.1.1 2 Unit 3 Safetv Relief Valve PCV-468

a. Inspection Scope

The team inspected the Unit 3 pressurizer safety relief valve (SRV), PCV-468, to verify it was capable of performing its design basis function. The team reviewed the UFSAR, the technical specifications, drawings, and procedures to identify the design basis requirements of the valve. The team verified that the SRV was tested in accordance with the TS requirements. The team reviewed design documentation for sizing and lift setpoints, and the analysis for overpressure protection capability of the valve to verify the valve met design requirements. The team interviewed Entergy engineers, discussed SRV performance and trending, and reviewed the valve's maintenance and in-service test history. Additionally, the team reviewed associated CRs and the latest system health report to assess the material condition of the valve.

b.

Findinqs No findings were identified.

.2.1.1 3 Unit 3 Power Operated Relief Valve 455C

a. Inspection Scope

The team inspected the Unit 3 power-operated relief valve (PORV) 455C to verify that it was capable of meeting its design basis requirements. The team reviewed applicable portions of the UFSAR, the reactor coolant system (RCS) DBD, the TSs and associated bases, drawings, and procedures to identify design basis requirements for the PORV.

The PORV design basis functions included plant pressure control at normal operating temperature and pressure, reactor vessel low-temperature over-pressure protection, and to provide a flow path for primary side feed and bleed operations using the EOPs.

Surveillance test and operating procedures were reviewed to assess whether the PORV was appropriately tested and operated within required design limits and whether tests adequately verified component functionality. The team compared recent as-found test and inspection results to established acceptance criteria to evaluate the as-found conditions and assess whether those conditions conformed to design basis assumptions and regulatory requirements. Maintenance records were reviewed to determine whether maintenance was performed in accordance with established procedures and vendor recommendations. The team interviewed Entergy engineers regarding the design, operation, testing, and maintenance of the PORV, including recent test results, and operating and maintenance history. Finally, the team reviewed recent system health reports, maintenance work orders, and CRs to determine whether there were any adverse operating trends.

b.

Findinss No findings were identified.

2.1.14 Unit 2 Containment Pressure Relief Valves (PCV-1190. 1191. and 1192)

a. Inspection Scope

The team inspected containment pressure relief valves PCV-1 190, 1 191 , and 1192 to verify the valves were capable of performing their design functions as described in the UFSAR. These valves are designed to provide controlled containment pressure relief via the plant vent during normal power operation and during plant cooldown if the containment purge system is not available. The valves are also designed to automatically close and isolate the containment pressure relief line upon receiving a containment isolation signal or a containment high radioactivity signal. Instrument air is the normal supply to actuate PCV-1 190, 1 191, and 1192. A local air accumulator and a local manual valve operator are installed to provide operators with two methods to operate the containment pressure relief valves if instrument air is not available. The team reviewed design calculations, periodic TS surveillance test records, and selected drawings to confirm the valves' capability. The team reviewed the adequacy of procedures which direct operation of the containment pressure relief valves. The team reviewed operator training lesson plans and performed a field walkdown with Entergy engineers to assess the material condition of the valves, and to verify procedures and operator knowledge were sufficient to ensure this pressure relief path was functional.

The team also reviewed vendor manuals, maintenance work orders, preventive maintenance documents, engineering modifications, and selected CRs to evaluate whether appropriate maintenance was performed.

b.

Findinos No findings were identified.

.2.1.1 5 Unit 2 21 Recirculation Pump Discharoe Stop Valve 1802,4

a. Inspection Scope

The team inspected the recirculation pump discharge stop valve, MOV-18024, to verify it was capable of performing its design function. The team reviewed the UFSAR, the lP2 Probabilistic Safety Assessment ECCS Recirculation System Notebook, calculations, and procedures to identify the design basis requirements of the valve. Following the ECCS injection phase in response to a LOCA, operators transfer to long term core cooling and containment spray using the recirculation system. Recirculation pump 21 discharges water through MOV-1802A to the reactor vessel. This establishes a long term core cooling flow path that remains internal to the containment. The team reviewed accident system alignments to determine if component operation was consistent with design and licensing bases assumptions and plant drawings. The team reviewed valve testing procedures and valve specifications to ensure consistency with design basis requirements. The team reviewed periodic verification MOV diagnostic test results and stroke test documentation to verify acceptance criteria were met and consistent with the design basis and TS requirements. Additionally, the team verified the valve safety function was maintained in accordance with Generic Letter (GL) 89-10 guidance by reviewing torque switch settings, performance capability, and design margins. The team interviewed the MOV program 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 verify that deficiencies were appropriately identified and resolved and that the valve was properly maintained. The team performed a review of the valve interlock design and testing to ensure that the valve and other associated ECCS components would function as designed under the most limiting design basis condition, including a single failure of a valve or power supply. ln addition, the team observed plant staff operate MOV-18024 and establish low-head internal recirculation cooling using emergency operating procedures at the Unit 2 control room simulator.

Findinss No findings were identified.

.2.1.1 6 Unit 2 Component Coolinq Water Heat Exchanqer 22

a. Inspection Scope

The team inspected the 22 CCW heat exchanger (HX), to verify that it was capable of meeting its design bases requirements. The team reviewed the UFSAR, the lP2 Probabilistic Safety Assessment CCW system notebook, the lP2 CCW DBD, drawings, and procedures to identify the design basis requirements of the heat exchanger. The CCW system circulates cooling water to several important components during both normal plant operation and post accident mitigation. One CCW HX is required to be capable of transferring heat from post LOCA loads (i.e., RHR HXs, safety injection pump motors) to the service water system to support long term core cooling using the worst case design assumptions (i.e., service water temperature of 95 degrees Fahrenheit).

The team reviewed design calculations, operational procedures, and test results to verify design requirements were met. The team also reviewed selected maintenance records, and the last three biennial CCW HX inspection and eddy-current test records to verify overall component health. Finally, CRs and the latest system health report were reviewed to verify deficiencies were appropriately identified and resolved, and that the CCW HX was properly maintained.

b.

Findinqs No findings were identified.

.2.1.1 7 Unit 3 Component Coolino Water MOV 8228

a. Inspection Scope

The team inspected the 32 RHR HX CCW outlet valve, MOV-8228, to verify it was capable of performing its design functions. The valve is designed to automatically open upon receipt of a safety injection signal, providing cooling water flow through the shetl side of the RHR HX. The valve is also a containment isolation valve which must be capable of isolating the CCW line containment penetration. The team reviewed the UFSAR, the lP3 Probabilistic Safety Assessment CCW System Notebook, design calculations, and procedures to identify the design basis requirements of the valve. The team also reviewed accident system alignments to determine if component operation would be consistent with the design and licensing bases assumptions. The Technical Specifications, valve test procedures, and valve specifications were also reviewed to ensure consistency with design basis requirements. The team reviewed periodic verification diagnostic test results and stroke test documentation to verify acceptance criteria were met and consistent with the design basis. Additionally, the team verified the valve safety function was maintained in accordance with GL 89-10 guidance by reviewing torque switch settings, performance capability, and design margins.

The team interviewed the MOV program engineer to gain an understanding of maintenance issues and overall reliability of the valve. The team conducted a walkdown to assess the material condition of the valve, and to verify the installed valve configuration was consistent with design basis assumptions and plant drawings. The team reviewed PM records to verify the valve was maintained consistent with manufacturer recommendations and industry operating experience lessons learned. The team verified that the voltage used in the valve thrust and torque limits calculation enveloped the calculated available voltage at the motor terminals under degraded voltage conditions to ensure the voltage was sufficient for valve operation. The control voltage drop calculations, controlfuse sizing, and thermal overload sizing were reviewed to ensure the availability of the circuit on demand. Finally, CRs were reviewed to verify that deficiencies were appropriately identified and resolved, and that the valve was properly maintained.

b.

Findinqs No findings were identified.

2.1.18 Unit 3 480 Volt Bus 6A

a. Inspection Scope

The team inspected the Unit 3 480V Bus 6A to verify it was capable of performing its design function. The team reviewed bus loading calculations, selected portions of the ETAP model recently prepared for the Unit 3 electrical system, and the existing load flow analysis to determine the level of anticipated bus loads under various operating and accident conditions. The team evaluated breaker and bus ratings and the setting of amptectors to evaluate the adequacy of the bus and breakers to carry anticipated loads under limiting conditions. Additionally, the team reviewed the results of short circuit calculations and switchgear modifications to verify the capability of the circuit breakers to withstand and interrupt maximum calculated faults. The review included electrical protection settings, equipment ratings, prevention of spurious tripping, upstream-downstream coordination, and capability of protective devices to guard against low magnitude faults. The team reviewed the voltage profile of the offsite system, voltage drop calculations, and the degraded voltage relay settings to confirm that adequate voltage was available at the terminals of the safety-related loads under worst case operating and accident conditions. The team also reviewed breaker control wiring diagrams to ensure operation conformed to the system design requirements. The review included a verification that adequate voltage was available to the control circuits for the proper closing and tripping of breakers and that actuation of the degraded voltage and loss of voltage relays initiated the EDG starting sequence. The team reviewed the latest system health report, the results of recent maintenance and test activities, and resolution of selected CRs to ensure that the bus and breakers were maintained in an acceptable operating condition. Additionally, the team conducted a walkdown of the bus to evaluate the configuration and material condition of the equipment.

Findinqs No findings were identified. Section 1 R21

.2.1 .1 documents a finding associated with a

design deficiency in the review of the associated Unit 3 switchgear room relative to postulated HELB conditions in the turbine building.

.2.1.1 9 Unit 2 Anticipated Transient Without Scram Mitiqation Svstem Actuation Circuitrv

lnspection Scope The team inspected the design and operation of the Unit 2 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 logic cabinets in the control room to assess the material condition of the system. The team interviewed Entergy engineers to ensure recommended maintenance had been established through the PM program and design changes had been satisfactorily implemented. Additionally, the team reviewed a sample of completed work orders and CRs to determine whether there were any adverse equipment issues.

b.

Findinqs No findings were identified.

.2.1.2 0 Unit 3 Main Steam lsolation Valve MS-1-33

a. Inspection Scope

The team inspected the MSIV, MS-1-33, to verify that the valve was capable of performing its design basis function to close and isolate the steam generators during a design basis event. The air operated MSIV is a normally open valve designed to automatically close on receipt of signals indicating a steam line break. The team reviewed calculations for valve stem thrust and actuator inputs to ensure that the valve was capable of operation under the worst case differential pressure conditions. The team reviewed main steam flow diagram 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 MSIV and the associated steam lines to assess the material condition. The team interviewed Entergy engineers to ensure recommended maintenance had been established through the PM program. Additionally, the team reviewed completed work orders, CRs, and system health reports to determine whether any adverse equipment operating trends existed.

Findinqs No findings were identified.

.2.2 Review of Industrv Operatins Experience and Generic lssues (3 samples)

The team reviewed selected OE issues for applicability at Indian Point Units 2 and 3.

The team performed a detailed review of the OE issues listed below to verify that Entergy had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.

.2.2.1 NRC Information Notice 2011-14, Component Coolinq Water Svstem Gas Accumulation

and Other Performance lssues

a. Inspection Scope

The team assessed Entergy's applicability review and disposition of NRC Information Notice (lN) 2011-14. This lN discussed recent industry OE regarding air intrusion into CCW systems, as well as other CCW system performance issues including protection from HELBs and seismic events. The team reviewed the Unit 2 and Unit 3 CCW system operating, fill and vent, and alarm response procedures to verify that Entergy's procedures adequately addressed the concerns identified in the lN. In addition, the team performed several Unit 2 and Unit 3 walkdowns of accessible CCW piping and surge tanks, reviewed CCW system corrective action CRs, and interviewed design engineers to independently verify that the CCW systems were adequately designed to ensure protection from licensing basis events postulated in the lN.

b.

Findinqs No findings were identified.

.2.2.2 NRC Information Notice 2010-23, Malfunctions of Emerqencv Diesel Generator

SpeedSwitch Circuits a.

lnspection Scope The team assessed Entergy's applicability review and disposition of NRC lN 2010-23.

The lN was issued to inform licensees about OE regarding electrical component malfunctions within speed switch circuits that rendered EDGs inoperable at two US nuclear power plants. Additionally, the lN described the root causes and corrective actions taken for these events to ensure the affected and associated EDGs remained operable and reliable. The team assessed Entergy's evaluation of the lN as it applied to the lndian Point Units 2 and 3, including their review of EDG design, to ensure speed switch circuits were maintained reliable or speed switch malfunctions would not render the EDG inoperable. The inspection included a review of corrective action documents and interviews with engineering personnel.

b.

Findinss No findings were identified.

.2.2.3 NRC Information Notice 2010-03. Failures of Motor Operated Valves Due to Deqraded

Stem Lubricant

a. Inspection Scope

The team assessed Entergy's applicability review and disposition of NRC lN 2010-03 for lndian Point Units 2 and 3. The lN was issued to inform licensees of adverse consequences and industry experience associated with recent MOV failures due to degraded lubricant on the valve stem and the actuator stem nut threaded area. The principle causes for the degraded lubricant condition were inadequate lubrication PM task frequencies, use of lubricant beyond its specified shelf life, and cross-contamination of the stem lubricant by the MOV actuator internal grease. The team evaluated the adequacy of Entergy's evaluation of the lN by reviewing specific CRs, results of MOV periodic inspections for a sample of safety related MOVs, diagnostic testing results, evaluations of lubricant material acceptability, periodic MOV stem lubrication maintenance procedures, shelf life control procedures, and by conducting interviews with engineering personnel.

b.

Findinqs No findings were identified.

4. OTHER AGTIVITIES

4c.A2 ldentification and Resolution of Problems (lP 71152)

Inspection Scope The team reviewed a sample of problems that Entergy had previously identified and entered into the CAP. The team reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions. In addition, CRs written on issues identified during the inspection, were reviewed to verify adequate problem identification and incorporation of the problem into the corrective action system.

The specific corrective action documents that were sampled and reviewed by the team are listed in the Attachment.

Findinqs No findings were identified.

4046 Meetinos, includins Exit On November 9, 2012, the team presented the inspection results to Mr. John Ventosa, Site Vice President, and other members of the Entergy staff. The team verified that no proprietary information was retained by the inspectors or documented in the report.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Enterqv Personnel

J. Ventosa, Site Vice President

J. Bencivenga, Design Engineer

G. Dahl, Licensing Specialist

M. Hagstrom, System Engineer

S. Malinski, Design Engineer

A. Melody, System Engineer

V. Meyers, Design Engineering Supervisor

T. McCaffrey, Design Engineering Manager

M. Radvansky, Design Engineer

J. Ratfaele, Design Engineering Supervisor

H. Robinson, Design Engineer

R. Sergi, Design Engineer

J. Zarrella, Programs and Component Engineer

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Open and

Closed

N CV 05000 247 t20 1 2007 -0 1 Inadequate Design Verification that Bus 6A supply breaker amptector would not inadvertently trip and lockout bus during degraded grid accident Sl load current (Section 1R21.2.1.1)

NCV

05000247 & 286t2012007 -02 lnadequate Turbine Building HELB evaluation for effect on Safety Related Equipment (Section 1R21.2.1.1)

NCV

05000247 & 286t2012007-03 Inadequate Verification of Design Analyses for Recirculation Pump NPSH (Section 1R21.2.1,2)