IR 05000247/2012007
| ML12356A304 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 12/21/2012 |
| From: | Doerflein L T Engineering Region 1 Branch 2 |
| To: | Ventosa J A Entergy Nuclear Operations |
| References | |
| IR-12-007 | |
| Download: ML12356A304 (45) | |
Text
UNITED STATES NUCLEAR REGULATORY COiIMISSION REGION I 21OO RENAISSANCE BOULEVARD, SUITE 1OO KING OF PRUSSIA, PENNSYLVANIA 1940G2713 December 2L, 2012 Mr. John Ventosa Site Vice President Entergy Nuclear Operations, lnc.lndian Point Energy Center 450 Broadway, GSB Buchanan, NY 1051 1-0249
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 cc w/encl.: Distribution via ListServ J. Ventosa ln accordance with Title 10 of the Code of FederalRegulations (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:/iwww.nrc.oov/readinq-rm/adams.html (the Public Electronic Reading Room).
Sincerely,/RN Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Docket No.: 50-247150-286 License No.: DPR-26/DPR-64
Enclosure:
f nspection Report 05000247 120120Q7 and 05000286/2012007 W
Attachment:
Supplementary Information cc w/encl.: Distribution via ListServ Distribution Mencl: (via E-mail)W. Dean, RA (RIORAMAIL RESOURCE)D. Lew, DRA (RIORAMAIL RESOURCE)D. Roberts, DRP (RIDRPMAlL RESOURCE)P. Wilson, DRP (RIDRPMAIL RESOURCE)C. Miller, DRS (RiDRSMAIL RESOURCE)J. Clifford, DRS (RIDRSMAIL RESOURCE)C. Santos. Rl OEDO M. Gray, DRP B. Bickett, DRP S. McCarver, Acting Rl A. Rao. DRP A. Ayegbusi, Acting SRI D. Hochmuth.
AA RidsNrrPMlndianPoint Resource RidsNrrDorlLpll
-1 Resource ROPreport Resource DOCUMENT NAME: G:\DRS\Engineering Branch 2\Arner\lndian Point combined CDBI 2012\lndian Point 2&3 CDBI 2012 Revl.doc ADAMS ACCESSION NUMBER: M1123564304 V n Publicly Available Non-Publicly Available V Non-sensitive n Sensitive V suNstReview Docket No: License No: Report No: Licensee: Facility: Location: Inspection Period: Inspectors:
Approved By: U.S. NUCLEAR REGULATORY COMMISSION REGION I 50-247t50-286 DPR-26/DPR-64 05000247 120 1 2007 a nd 05000286 l2O1 2007 Entergy Nuclear Northeast (Entergy)lndian Point Nuclear Generating Units 2 and 3 450 Broadway, GSB Buchanan, NY 1051 1-0249 October 15 through November 9,2012 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)
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.
2.2 Results of Detailed Reviews.2.1 Results of Detailed Component Reviews (23 samples).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)Enclosure 3 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 4 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.Attachment 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 Enclosure 5 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 6 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 Enclosure 7 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 Enclosure 8 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 21
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 Enclosure b.9 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.
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)Enclosure 10 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 Enclosure 11 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)Enclosure 12.2.1,3 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 Enclosure 13 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.Enclosure b. Findinss No findings were identified.
.2.1.6 Service Water Pump 34
a. Inspection Scope
The team inspected the 34 service water (SW)the Hudson River, the ultimate heat sink, to requirements for the pump. The team reviewed consistent with the design basis assumptions.
criteria were met and that Entergy appropriately requirements.
The team reviewed motor electrical coordination curves, and power calcu and configuration control.b. Findinos No findings were identified.
.2.1.7 Safetv Iniection
Pump 32
a. Inspection Scope
The team inspected the 32 Sl pump to verify basis function.
The Sl pumps are an integral systems (EGCS) designed to provide adequate conditions.
The team reviewed applicable and drawings to identify the design basis requi design calculations to assess available pump flows. The team reviewed pump IST results and Enclosure to verify that it was capable of performing its design basis function.
The Unit 3lSW system supplies cooling water from 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 calculations and SW system hydraulic analyses to assess available pump NPPH and determine required system flows. The team reviewed the SW pump IST re$ults and system flow verification test results to verify acceptance criteria were met an{ that the acceptance criteria were , the team reviewed pump data trends of vibration, differential pressure and flowlrate test results to verify acceptance and evaluated adverse trends.The team also verified that design requirements pnd operational limits were properly translated into operating instructions and alarm rBsponse procedures.
The team inspected the 34 SW pump motor to verify it wa$ capable of meeting the pump power data, protective relay setpoint data, 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 it was capable of performing its design of the emergency core cooling cooling under plant accident s of the UFSAR, the Sl system DBD, for the pump. The team reviewed H and determine required system flow verification test results to 15 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 Enclosure 16 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 17 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.
Findinqs No findings were identified.
b.Enclosure 18.2.1.12 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.
a.19 2.1.14 Unit 2 Containment Pressure Relief Valves (PCV-1190.
1191. and 1192)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.
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 b.Enclosure 20 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 Enclosure 21 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 Enclosure 22 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..2.1.19 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 Enclosure
.2.2.2 .2.1
a.23 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.
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.
NRC Information Notice 2011-14, Component Coolinq Water Svstem Gas Accumulation and Other Performance lssues 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.Findinqs No findings were identified.
b.Enclosure
.2.2.2 a..2.2.3
a.24 NRC Information Notice 2010-23, Malfunctions of Emerqencv Diesel Generator SpeedSwitch Circuits 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.
b.NRC Information Notice 2010-03. Failures of Motor Operated Valves Due to Deqraded Stem Lubricant 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.
Findinqs No findings were identified.
4.25 OTHER AGTIVITIES 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.
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.4c.A2 4046 Enclosure A-1
=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 NCV
- 05000247 & 286t2012007
-02 NCV
- 05000247 & 286t2012007-03
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)
lnadequate
Turbine Building HELB evaluation
for effect on Safety Related Equipment (Section 1R21.2.1.1)
Inadequate
Verification
of Design Analyses for Recirculation
Pump NPSH (Section 1R21.2.1,2)
LIST OF DOCUMENTS
REVIEWED Calculations and Enoineerino Evaluations
- 2-1206505,
- AC-MOV-9ZZA
and B - Differential Pressure Calculation, Rev. 1 98-049, lP3 Auxiliary Feedwater System
- PROTO-FLO
- Thermal Hydraulic Model, Rev. 4 00186-C-020, AOV Component Level Calculation for Rising Valves
- RC-PCV-4S5C
and 456 at Indian Point 3 Nuclear Power Plant. Rev. 0 6604.003-8-SW-140, EDG Jacket Water Tube Plugging Limit, Rev. 0 6604.219-8-SW-024, Diesel Generator Lube Oil Cooling, Rev. 2 6604.266-F-SW-005, Hydraulic Survey, Essential Service Water System Header, Rev. 5 8399.003-F-SW-215, Calculation of Flow through Emergency Diesel Generator Coolers in Post-LOCA
- Recirculation Mode, Rev. 0 8399.164-2-SW-088, Service Water Flows to Lube Oil and EDG Jacket Water Coolers, Rev. 2 59379-ER-01, Indian Point Unit 3 Stretch Power Uprate Project, BOP Engineering Report, dated
- 2122105 93162-C-37, Valve Thrust Assessment (Weak Link Analysis), Anchor Darling Gate Valve: Sl-MOV-889A
and B, Rev. 2
- ALION-REP-IPEC-7338-001, Test for Success Prototype Array Head Loss Chemical Effects Test Report, Rev. 1
- CN-SEE-00-63, lP2 Diesel Loading Study - Pumps, Rev. 1
- EGE-00006, Indian Point Generating Station Emergency Diesel Generator Upgrade
- DB-75 Breaker and Switchgear Testing, Rev. 0
- EGE-00022, Indian Point
- DB-75 Breaker Overload Capability during Degraded Voltage Conditions with Offsite Power. Rev. 1
- FEX-00039, Emergency Diesel Generator Loading Study, Rev. 2
- FEX-00130, lP2 Short Circuit Analysis of the Electrical Distribution System, Rev.0
- FEX-00141, lP2 Amptector Setting Verification, Sensor and Tolerances, Rev.'1
- FEX-00143, lP2 Load Flow Analysis of Electrical Distribution System, Rev.1
- FIX-00138, Indian Point 2 ITS Allowable Value - 480 Volt Bus Undervoltage and Degraded Voltage (Westinghouse
- CN-SSO-02-50), Rev 0
- FMX-00275, Pipe Flow Analysis for AFW System, Rev. 2
- GSX-00035, lP2 EOP Setpoint Rev. 1C+ Upgrade Project: Emergency Diesel Generator Load EOP Setpoint Documentation Analysis (CN-P0E-01-9), Rev. 0lP3-CALC-04-00809, Brake Horsepower Values Related to Certain Pumps and Fans for EDG Electrical Loading, Rev. 3 lP-CALC-06-00231, Indian Point Unit 2 Sl Recirculation (LHSI and HHSI) Performance for the Containment Sump Program, Rev. 1 lP-CALC-O7-00054,Indian Point Unit 3 Sl Recirculation (LHSI and HHSI) Performance for the Containment Sump Program, Rev. 2 lP-CALC-O9-179,Indian Point ECCS Sump Strainer Certification Calculation based on NPSH Minimum Flow, Structural Limit and Void Fraction Requirements, Rev. 3 lP-CALC-09-00245,Indian Point 2 Evaluation of Revised Auxiliary
- CCW Pump Performance on Post-LOCA
- CCW System Operation, Rev. 0 lP-CALC-1
- 1-0001 1, Evaluation of Emergency Diesel Generator (EDG) Fuel Oil Usage Accounting for lssues ldentified During the lP3 2010 NRC CDBI, Rev. 0 Attachment
- A-3lP-CALC-11-00025, Head Correction for the Results of the High Head Safety Injection (HHSI)Pump IST Full Flow Test, Rev. 0 lP-CALC-11-00058, lP3 Emergency Diesel Generator (EDG) Fuel Oil Consumption Licensing Basis Calculation, Rev. 0 lP-CALC-11-00082, lP3 Electrical Distribution System ETAP Model, Rev. 0 lP-CALC-12-00066, Seismic Evaluation of the City Water Storage Tank, Rev. 0lP3-CALC-ED-00201, 480V Buses 2A, 34, 5A, and 6,4 Non Accident Loading, Rev. 3!P3-CALC-ED-00207
,480V Buses 2A, 3A, 5A, and 6,4 and EDG's 31 , 32 and 333 Accident Loading, Rev. 8
- IP3-CALC-ED-00358, 480V Bus and EDG Loading for Reactor Trip/No Sl, Rev. 2 lP3-CALC-ED-01074, F38-0042-
- 480 Volt Electrical Distribution System Evaluation of Thermal Overload Heater Sizing for MOV Motors, Rev. 1lP3-CALC-ED-01545, 480V Safety Related Switchgear Accident Operation at above 40 oC Ambient. Rev. 0 lP3-CALC-ED-03158, 6.gkv and 480V System Transient Voltage Analysis during Degraded Voltage Condition, Rev. 1
- IP3-CALC-EDG-03466, Determination of Starting Air Receiver Pressure after a 17 Second Over-Crank.
- Rev.0 lP3-CALC-EG-00217, Emergency Diesel Generator Storage Tank Level Setpoints, Rev. 4 I P3-CALC-EL-O
- 97 2, F 38-00421 480V E lectrical Distri buti on System I P3 Deg raded G rid Voltage Study, Rev. 1 lP3-CALC-HVAC-00408, EDG Room Ventilation System Evaluation, Rev. 2 lP3-CALC-MS-O1347, Redesign of Pipe Support
- MS-R-1-3-H, Rev. 1 lP3-CALC-Sl-01003, Thrust and Torque Limits Calculation for Sl-MOV-8898, Rev. 4 lP3-CALC-Sl-01008, Thrust and Torque Limits Calculation for Sl-MOV-747, Rev.6 lP3-ECAF-Bus
- 5A-188C123B, Bus 5,{-238 33 EDG Breaker Coordination, Rev. 0 lP-RPT-09-00014, Critical Submergence Evaluations Related to Surface Vortices in Nuclear Safety and Augmented Quality Tanks/Pumps at IPEC, Rev. 1 lP-RPT-10-00078, Emergency Diesel Generator Starting Air System Testing Data Evaluation, Rev.0 lP-RPT-10-00006, Minimum Flow Calculation, Rev. 0
- MEX-00011-01, Valve Thrust Calculation
- MOVs 1802N8 ALTMN Calculation
- 2167-TR-06, Rev. 1
- MMS-00134, Analysis of Thrust and Torque Limits for Motor Operated Valve 1802A, Rev. 8
- PGI-00531, AOV Component Level Calculation for Pressure Relief Containment lsolation Valves
- PCV-1 190, -1 191 , -1192, Rev. 0
- PGI-00473, lP2 Motor Operated Valve TerminalVoltage;
- Altran Calculation No. 99621-C-002, Rev.3
- PGI-00475, lP2
- PGl-00531, AOV Component Level Calculation for Pressure Relief Containment lsolation Valves
- PCV-1 190, -1 191, -1192, Rev. 0 RC and
- SGSS-C-411, CCW Pump NPSH, Rev. 1 RFS-lN-983, NPSH of Residual Heat Removal and Safety lnjection Pumps, Rev. 1
- SGX-00013, Indian Point 2 - Setpoint Change for under Voltage Relays on 480V Buses 24, 3A, 5A and 6A, Rev. 5
- SGX-00018, lndian Point 2 - Station Service Transformer No. 6, 480 Volt Circuit Breaker Setting, Rev.0 Attachment
- SGX-00048 , lP2 48OV Switchgear Coordination Calculation for Switchgear and 22, Task
- CLC-2-12A, Rev. l
- SGX-00073, Bus Transfer (Transient)
- Analysis of the lP2 Electrical Distribution System 4, Rev. 1
- WCAP-12312, Safety Evaluation for an Ultimate Heat Sink Temperature Increase to 95F at lndian Point Unit 2, Rev.2
- WCAP-12655, Emergency Diesel Generator Loading Study, as amended by Stretch Power Uprate (SPU) Project Letter
- IPP-03-187 (PU2-W-03-113)
tP2-2005-01401
tP2-2005-26433
tP2-2006-06850
tP2-2008-04243
tP2-2009-00868
tP2-2009-02567
tP2-2009-03489
lP2-2009-03666
tP2-2009-04215
tP2-2009-04429
tP2-2009-04450
tP2-2009-04962
tP2-2010-01657
tP2-2010-02435
lP2-2010-05810
- P2-2A10-07322
tP2-2011-04479
lP2-2Q11-05622
lP2-2011-05904
tP2-2012-00596
tP2-2012-00611
tP2-2012-00694
tP2-2012-01005
lP2-2012-01467
lP2-2012-01641
tP2-2012-02655
tP2-2012-02924
tP2-2012-04568
tP2-2012-06230*
lP2-2012-06243*
tP2-2012-06255*
lP2-2012-06368*
lP2-2012-06368" lP2-2012-06431*
tP2-2012-06487*
tP2-2012-06493*
tP2-2012-06541" tP2-2012^06549*
lP2-2012-06596*
tP2-2012-06613" lP2-2012-06615
tP2-2012-06620" tP2-2012-06625*
tP2-2012-06633
tP2-2012-06646*
tP2-2012-06653*
lP-2-2A12-06666*
tP2-2012-06669*
tP2-2012-06676*
tP2-2012-06683" rP3-2004-00203
tP3-2004-0282'l
rP3-2005-04001
rP3-2007-00453
lP3-2007-00542
tP3-2007-00673
tP3-2007-04662
rP3-2008-01016
lP3-2009-04452
lP3-2009-04454
lP3-2009-04498
tP3-2009-04499
tP3-2009-04502
tP3-2009-04819
lP3-2010-00214
lP3-2010-01034
tP3-2010-01268
tP3-2010-02904
lP3-2010-03088
tP3-2010-03554
tP3-2010-03818
lP3-2010-06006
lP3-2011-01232
tP3-2011-01465
tP3-2011-01805
lP3-2011-02397
tP3-2011-0240s
f P3-2011-02587
lP3-2011-02867
lP3-2011-04034
tP3-2011-04045
lP3-2011-04046
tP3-2011-04568
tP3-2011-04649
tP3-2011-05089
tP3-2012-00232
tP3-2012-00331
tP3-2012-00382
tP3-2012-00420
tP3-2012-01090
tP3-2012-01748
tP3-2012-02375
tP3-2012-02447
tP3-2012-02804
lP3-2012-02894
tP3-2012-02921
tP3-2012-03037
tP3-2012-03171
- LP3-2012-03191*
tP3-2012-03212*
tP3-2012-03218*
tP3-2012-03239*
- 1P3-2012-03258" tP3-2012-03262*
tP3-2012-03356*
tP3-2012-03366*
tP3-2012-03408
tP3-2012-03465
tP3-2012-03466
lP3-2012-03493
tP3-2012-03543*
tP3-2012-03546*
tP3-2012-03554*
tP3-2012-03556.
tP3-2012-03558*
tP3-2012-03563*
lP3-2012-03564*
tP3-2012-03566*
tP3-2012-03575*
tP3-2012-03584*
tP3-2012-03590.
- CR written as a result of this inspection
- Design and Licensinq Basis Documents lP2-CCWS DBD, Design Basis Document for Component Cooling Water, Rev. 1 lP3-DBD-304, Design Basis Document for the Service Water System, Rev. 3lP3-DBD-306, Design Basis Document for Safety Injection System (SlS), Rev. 5lP3-DBD-308
- Tab 1, Design Basis Document for the Component Cooling Water System, Rev. 3 lP3-DBD-322,lndian Point Unit No. 3 High Energy Line Break Outside Containment Design Basis Document, Rev. 1 lP3-DBD-324, Design Basis Document for the Emergency Diesel Generators and Appendix R Diesel Generator.
- Rev. 1
- NL-80-480, Consolidated Edison Company of New York letter to NRR, Response to NRC's May 20, 1980, Request for Additional lnformation Concerning the Effects of Flooding due to Failure of Non Seismic Class I Equipment, dated 7l14l81 NRC Regulatory Guide 1.137, Fuel-Oil Systems for Standby Diesel Generators, Rev. 1 NRC Safety Evaluation Report for License Amendment No. 259 to
- DPR-26, lndian Point Nuclear Generating Unit No. 2, Regarding Emergency Diesel Generator Surveillance Test, 04t22t09 NRR letter to Consolidated Edison Company of New York letter, Safety EvaluatiOn Report: Susceptibility of Safety-Related Systems to Flooding from Failure of Non-Category
- I Systems for Indian Point Nuclear Power Station Unit 2, dated
- 12118180 Drawinqs
- 4148012, Alarm Panel Section of Supervisory Panel Board in CCR, Rev. 36
- 4206143,lP2
- Replacement of Containment Pressure Relief Valves
- PCV-1190, 1191, and 1192, Rev. 9 A208088, lP2 One Line Diagram of 480 VAC SWGRS 21 and22, Bus 2A, 34, 5A, and 64, Rev.44
- 4208377,1P2
- Main One Line Diagram, Rev. 17
- 4208507 , lP2 One Line Diagram, 480 VAC MCCs 28 and 210, Rev. 17
- 4214529-11, Control Building Fire Dampers, Unit 2, Rev. 11
- 8225130, lP2 Elementary Wiring Diagram of Recirculation Pump # 21, Rev. 6 8228595-4, Heating Ventilation and Air Conditioning Fire Dampers Details and Sections, Rev. 4
- 208500, lP2 One Line Diagram for 480VAC
- MCC-26AA and 2688 and 120VAC Distribution Panels 1 and 2, Rev 47
- 225017,1P2
- Safeguard Actuation Safety Injection Schematic Train 'A', Rev. 23
- 225151, lP2 Elementary Wiring Diagram of Component Cooling Pump #23, Rev. 15
- 263242,1P2
- Pipe Penetration Area Control Air Valve
- PCV-1191 lnstrumentation, Rev.0
- 5008971 Sh. 28, Elementary Wiring Diagram, Safety Injection Pump 32, Rev. 10
- 5008971 Sh. 33, Elementary Wiring Diagram, Service Water Pump 34, Rev. 12
- 5008971 Sh. 116, Elementary Wiring Diagram, Valve Table - MOV, Rev. 11
- 5008971 Sh. 142, Elementary Wiring Diagram, Recirc Switch and Indicating Lights, Rev. 10
- 5008971 Sh. 153, Elementary Wiring Diagram, Motor Operated Valves Electrical, Rev. 9 617F644,lP3
- 480V One Line Diagram, Rev 33 9321-F-3006,lP2
- Single Line Diagram 480V Motor Control Center 37,38,39, and 311, Rev.72 9321-F-3007,lP2
- Three Line Diagram Diesel Generator Low Voltage, Rev. 18 9321-F-3008, lP2 Single Line Diagram DC Power Panels 21 , 22,23, and 24, Rev. 92 Attachment
- 9321-F-4017-28, Control Building Heating Ventilation and Air Conditioning Plans and Sections, Unit 2, Rev. 6 9321-F-4040-12, Control Building Heating Ventilation and Air Conditioning Plans and Sections, Unit 2, Rev. 5 9321-F-20303, Flow Diagram, Fuel Oilto Diesel Generators, Rev. 29 9321-F-20333
- Sh. 1, Service Water System, Rev. 50 9321-F-21193, Flow Diagram, Lube Oilto Diesel Generators, Rev. 10 9321-F-27203, Auxiliary Coolant System Inside Containment Flow Diagram, Rev. 29 9321-F-27353
- Sh. 1, Safety lnjection System, Rev. 42 9321-F-27503
- Sh. 2, Safety Injection System, Rev. 53 9321-F-30063, lP2 Single Line Diagram 480V
- MCC 26A and 268, Rev. 96 9321-F-30063, lP3 Single Line Diagram 480V Motor Control Center 364, 368, and 36C, Sh. 1, Rev.77 9321-F-30063, lP3 Single Line Diagram 480V Motor Control Center 36D, and 36E, Sh.2, Rev. 10 9321-F-30073, lP3 Three Line Diagram Low Voltage, Rev. 29 9321-F-33853, lP3 Electrical Distribution and Transmission System, Rev. 18 9321-F-40563-5, Control Building Heating Ventilation and Air Conditioning Plans and Sections and Details, Unit 3, Rev. 5 9321-F-41023, Flow Diagram, Ventilation System EDG Building, Rev. 23 9321-H-20283, Flow Diagram, Jacket Water to Diesel Generators, Rev. 24 9321-H-20293, Flow Diagram, Starting Air. to Diesel Generators, Rev. 34 9321-H-20303, Flow Diagram, Fuel Oilto Diesel Generators, Rev. 29 9321-LL-31
- 17,480 V.A.C. Bus 5 A Interlocking Relays, Sheet 38, Rev. 28 9321-LL-31173
- Shts. 4, 5, and 6, Schematic Diagram 480V Switchgear
- 31, Revs. 16,22, and 25 9321-LL-31183, Schematic Wiring Diagram 480V Switchgear
- 2, Bus 64 lnterlocking Relays, Rev.22 9321-LL-31183, Schematic Wiring Diagram 480V Switchgear
- 2, Sheet 16, Rev. 7 9321-LL-31
- 183, Schematic Wiring Diagram 480V Switchgear
- 2, Sheet 1 8, Rev. 10 lP2-S-000200, lP2 RHR Heat Exchanger
- 2U CCW Outlet lsolation Valve
- MOV 822A, Rev. 2 lsl-4022,1P2
- Inservice lnspection Program Ventilation System Containment Primary Aux Building, Rev. 2 Enqineering Evaluations
- CCR-AC-2, Rev. 0
- EC-6350, lP2 EOP Setpoint Rev. 1C+ Upgrade Project: Emergency Diesel Generator Load EOP Setpoint Documentation Analysis, Rev. 0
- SPU Reconciliation Report to Calculation
- FEX-00039, Rev. 0
- MOV 536, Rev. 0
- EC 29813, Engineering Change Markup for lP3-CALC-ED-00801, Emergency Diesel Generators
- 31, 32, and 33 Non-Sl Blackout Loading (Revision
- 0), dated
- 813111 Hydraulic Model Evaluation of Service Water Pump Intake Indian Point Nuclear Power Station, Unit 3 Phase 2 Report, May 1986 lP2-2003-4732, Service Water Pressure Transient Apparent Cause Evaluation, dated 9115lO3 Attachment
lP2-2005-0370, Unit 2 Gas Build-Up in Safety lnjection Piping Root Cause Analysis Report, dated
- 211105 lP2-2009-3489
- CA-1, 23 Component Cooling Pump Failed to Start Apparent Cause Evaluation, dated
- 9129109 lP2-2009-4429
- CA-5, 23 Component Cooling Pump Capacity Apparent Cause Evaluation, dated 3t2t10 lP3-2007-0453, NUE Entered for Emergency Plan EAL 8.4.3 Root Cause Analysis Report, dated 3t2t07 lP3-2007-0673
- CA-1, Protective Relay Calibration
- PM Program Apparent Cause Evaluation, dated 3114lO7 lP3-2009-4454
- CA-l, Blown Fuse in 33 EDG Auxiliaries
- MCC 39 Cubicle SBL Apparent Cause Evaluation, dated
- 1219109 lP3-201
- 1-2397, Discharge Pressure Instrument
- PI/PT 922 Elevated Pressure Apparent Cause Evaluation.
dated
- 5113111 lP3-20114A46
- CA-1, Breaker 5215A Failed to Close Apparent Cause Evaluation, dated
- 9112111 lP3-2011-4649, Unit 3 Service Water Maintenance Rule (aX1) Action Plan, dated
- 12114111 lP3 Service Water Bay Level Operational Decision-Making lssue Action Plan, dated
- 215107 lP-RPT-04-00639, Indian Point Unit No.2 Emergency Diesel Generator Basler Exciter System Component Testing Summary Report,
- 916191 lP-RPT-09-00067, lndian Point Units 2 and 3 - Design Analytical Limits for Use in Development of Pump Testing Acceptance Criteria, Rev. 0 lP-RPT-10-00078, Emergency Diesel Generator Starting Air System Testing Data Evaluation, Rev.0lP-RPT-10-00080, Gas Accumulation Management Category 2 System Review, Rev. 0 LO-l P3LO-2AA7
-00258, I P3-2007-0453
- Effectiveness Review, dated 101 161 07
- MMM-89-03369-P, EDG Upgrade, 5/91
- NSE 99-03-004, EDG Short-Term Capacity Rating Clarification, Rev. 0
- NSE 92-3-144, EDG, Evaluation of EDG Operability with Tube Plugging in the Jacket Water Heat Exchanger, Rev. 2
- WCAP-12312, Safety Evaluation for an Ultimate Heat Sink Temperature lncrease to 95oF at lndian Point Unit 2, Rev. 2 90-334-MD, EDG Upgrade, Rev.2 Functional.
- Surveillance and Modification Acceptance Testing 0-GNR-403-ELC, Emergency Diesel Generator Quarterly Inspection, performed
- 8l I 51 1 I 0-GNR-404-ELC, Emergency Diesel Generator
- 2-Year Inspection, performed
- 818111 0-GNR-406-ELC, Emergency Diesel Generator
- 6-Year Inspection, performed
- 11112109 0-GNR-408-ELC, Emergency Diesel Generator
- 2-Year Inspection, performed
- 217112 0-VLV-412-MOV, Use of Motor Operated Valve Diagnostics, performed
- 29109 0-VLV-413-MOV, Motor Operated Valve Minor Preventative Maintenance, performed
- 23111 0-VLV-429-VSR, Safety Relief Valve Testing 21 and 23 EDG, performed
- 7111106 and8l7106 0-MS-425, Primary Injection Testing on
- DB-50/DB-75
- Breakers, performed
- 26107 2-BRK-013-ELC, Westinghouse, Model
- DB-75 Breaker - Corrective Maintenance, performed
- 27 108, 21 12110, and 1 I 1 1 I 12 2-BRK-01 6-ELC, Westinghouse, Model
- DB-75 Breaker - Preventive Maintenance, performed
- 26108, 2l9l 10, and I 15112 Attachment
- 2-BRK-021-CUB, Westinghouse
- 480V DB Series Breaker Cubicle Inspection and Cleaning, performed
- 27 108,
- 3122110, and
- 3112112 2-BRK-023-ELC, DB Breaker AmptectorMestector Overcurrent Test, performed
- 28108,
- 4128108,
- 2112110,
- 2118110,
- 312211 0, and
- 3114112 2-BRK-024-ELC, DB Breaker AmptectorMestector Calibration Test, performed
- 28108 and
- 2112110 2-lC-PC-l-L-12075, Diesel Generator Fuel Oil Day Tank No. 21 Level, performed
- 11110108 2-PC-OL27D, Bus 6A 480V Degraded Grid Voltage Relays Calibration, performed
- 9112111 2-PC-OL27H, Bus 6A 480V Undervoltage Relays Inspection and Calibration, performed
- 5110110 and
- 6127112 2-PC-R58, 480 Volt Undervoltage Relay Calibration, performed
- 2109 and9l14l11
- 2-PT-4042A, 21 FOST Underfilled Tightness Test, performed
- 817112 2-PT-M021A, Emergency Diesel Generator Load Test, performed
- 817112,916112, and 10t11t12 2-PT-R0844,21
- EDG 8 Hour Load Test, performed
- 318112 2-PT-M048, 480 Volt Undervoltage Alarm, performed
- 21112 2-PT-Q030C, 23 Component Cooling Water Pump, performed
- 26112 2-PT-Q48, AMSAC Logic, performed
- 9110112 2-PT-R013, Safety Injection System, performed
- 317112 2-PT-R083, AMSAC End to End Functional, performed
- 315112 2-TOP-01 6, 22 EDG Performance Test, performed
- 1011 1 110 3-BKR-016-CUB, Westinghouse
- 480V Switchgear Cubicle Inspection and Cleaning, performed
- 3/18/09 3-BKR-017-ELC, Current Sensor and/or Trip Unit Replacement, Setting and Testing, performed
- 2l1AA7, 3117 lO7 and 3/9/09 3-PT-M62C, 480V Undervoltage/Degraded Grid Protection System Bus 64 Functional, performed
- 9113112 3-BKR-018-ELC, Inspection, Lubrication, and Testing of Westinghouse
- 480V
- DS 532/632 Breakers, performed
- 3/6/09 3-PT-C2002B, Main Steam lsolation Valves, performed
- 418111 3PT-CS028, Pressurizer
- PORV and Block Valve Test (RC-PCV-45SC
and 456, RC-MOV-535
and 536), performed
- 1 1 lO9, 41 13109, 21.231 1 1, 31201 11, and 4l3l I 1 3-PT-Q022, Residual Heat Removal System Valves, performed
- 6114112 3-PT-R003D, Safety Injection Test, performed
- 411111 3-PT-R005A, Pressurizer Safety Valves Set Pressure and Seat Leakage Test (Utilizing an Outside Facility), performed
- 3117111 and
- 5110112 3-PT-M62C, 480V Undervoltage/Degraded Grid Protection System Bus 6,4 Functional, performed
- 10110112 3-PT-M079C, 33 EDG FunctionalTest, performed
- 813112 3-PT-M098, Emergency Core Cooling System (ECCS) Alignment Verification, performed
- 23112 3-PT-Q092D, 34 Service Water Pump, performed
- 8111112 and9l20l12
- 3-PT-Q1168,32
- Safety Injection Pump, performed
- 716112 3-PT-R003A4, Sl Recirculation Switches 1,6, and 8 Test, performed
- 319111 3-PT-R003C, Safety Injection Test Train 1 and Train 2, performed
- 411111 3-PT-R003D, Safety lnjection Test, performed
- 2111 3-PT-R003F, Non Sl Blackout Logic and ABFP Auto-Start Functional Test, performed
- 2111 3-PT-R023, ECCS Throttle Valves Position Verification, performed
- 413111 Attachment
- 3-PT-R064, Safety lnjection Pumps Full Flow and Check Valves Test, performed
- 3/31/11 3-PT-R160C, 33 EDG Capacity Test, performed
- 20111 3-TOP-209, 33 EDG Performance Test, performed
- 1015110 3-VLV-052-RCS, Pressurizer Power Operated Relief Valve (RC-PCV-455C, RC-PCV-456)
- Inspection and/or Overhaul, performed
- 20107
- EN-WM-105, lndian Point Unit 2 Relay 27-51l5A Calibration, performed
- 25109 and
- 813111 Miscellaneous AmendmentT4to facility Operating License No.
- DPR-26, dated
- 12110181 Amendment
- 165 to facility Operating License No.
- DPR-26, dated
- 9122193 3-AOP-SWL-1, Low Service Water Bay Level, Revision 0, IPEC Procedure Review and Approval Form, dated 3l2ll7 3-ARP-049, Panel Local - lntake Structure, Revision 2, IPEC Procedure Review and Approval Form, dated
- 312107 3-PT-D001, CCR TS Rounds, dated
- 1016112 3-RND-CV, Conventional Rounds, dated
- 9130112 -
- 1016112 INT-g1-566, Westinghouse Electric Corporation Letter to New York Power Authority, lndian Point Unit 3 Emergency Core Cooling System Pump Runout Limit lssues, dated
- 9127191 lP2 Licensed Operator Requalification Cycle 1 1.04.01 Schedule,
- 05104111 f P2 Licensed Operator Requalification Cycle 12.03.03 Schedule,
- 04101112 IP3LO-201
-001 70, Component Design Bases Pre-lnspection Self-Assessment
lP3-NSE-93-3-428480V, Nuclear safety Evaluation Covering Breaker lnterrupting Capability of the 480V ac Switchgear Breaker (DS-a16), Rev. 0
- IP3-RPT-MULT-01763, Evaluation of Power Operated Gate Valves for Pressure Locking and Thermal Binding in accordance with USNRC
- IP3-UT-12-015, Gas Intrusion - Various PAB and VC Locations per 3-PT-M108
- UT Gal i bration/Exami nation Report, performed
- 30 l 1 2lP3-UT-12-016, Gas Intrusion - Various PAB and VC Locations per 3-PT-M108
- UT Calibration/Examination Report, performed
- 1014112 Letter USNRC to Indian Point, Safety Evaluation Report, Susceptability of Safety-Related Systems to Flooding from failure of Non-Category
l Systems, dated December 18, 1980 Limitorque Technical Update 04-01, Crompton MOV Long Life / Exxon Nebula EP Compatability
- NL-20-141, 90-Day Response to Bulletin 2012-01, Design Vulnerability in Electric Power System, dated
- 10125112 NRC NUREG 1482, Guidelines for lnservice Testing at Nuclear Power Plants, Rev. 1
- SEP-IP2-lST-2,lP2
- Fourth Ten-Year lnterval Inservice Testing Program Plan, Rev. 0
- SEP-IP3-lST-2, lP3 Fourth Ten-Year Interval Inservice Testing Program Plan, Rev. 0 T59062-112/3, Wyle Laboratories As Received Test Report, dated
- 1111112 Operatino Experience
- LO-WTIPC-2011-29
- CA-136, Component Cooling Water System Gas Accumulation and Other Performance lssues (NRC lnformation Notice 2011-14), Rev.0 NRC Information Notice 97-90: Use of Nonconservative Acceptance Criteria in Safety-Related Pump Surveillance Tests, dated
- 12130197 Attachment
- NRC Information Notice 2008-02: Findings ldentified during Component Design Bases lnspections, dated 3/1 9/08 NRC lnformation Notice 2011-14. Component Cooling Water System Gas Accumulation and Other Performance lssues, dated
- 7118111 Operating
Procedures
- 1-ARP-002, Unit 1 Supervisory Panel, Rev. 21 2-AOP-CCW-1, Loss of Component Cooling Water, Rev. 2 2-AOP-FLOOD-1, Flooding, Rev. 8 2-AOP-LICCW-1, Leakage into CCW System, Rev. 4 2-ARP-SAF-1, Process Radiation Monitors, Rev. 36 2-ARP-SGF, Auxiliary Coolant System, Rev. 35 2-ARP-SJF, Cooling Water and Air, Rev. 40 2-E-0, Reactor Trip or Safety lnjection, Rev. 5 2-ECA-0.0, Loss of All AC Power, Rev. 11 2-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 7 2-ES-1.4, Transfer to Hot Leg Recirculation, Rev. 3 2-SOP-4.1.1, Component Cooling Filling and Draining, Rev. 8 2-SOP-4.1.2, Component Cooling System Operation, Rev.36 2-SOP-5.4.1 , Vapor Containment Pressure Reliefs, Rev. 18 2-SOP-AFW-001, AFW Operation, Rev. 4 2-SOP-AFW-002, AFW Support Procedure, Rev. 2 2-SOP-27.1.5, 480V System, Rev.44 2-SOP-27 .3.1.1 , 21 Emergency Diesel Generator Manual Operation, Rev. 22 3-AOP-480V-1, Loss of Normal Power to Any Safeguards
- 480V Bus, Rev. 7 3-AOP-CCW-1, Loss of Component Cooling Water, Rev. 5 3-AOP-SW-1, Service Water Malfunction, Rev. 2 3-AOP-SWL-1, Low Service Water Bay Level, Rev. 1 3-ARP-010, Panel SJF - Auxiliary Coolant System, Rev. 32 3-ARP-012, Panel SJF - Cooling Water and Air, Rev. 48 3-ARP-019, Panel Local- Diesel Generators, Rev. 26 3-ARP-049, Panel Local- Intake Structure, Rev. 6 3-E-0, Reactor Trip or Safety Injection, Rev. 3 3-ECA-0.0, Loss of All AC Power, Rev. I 3-ECA-0.1, Loss of AIIAC Power Recovery without Sl Required, Rev. 4 3-ECA-0.2, Loss of All AC Power Recovery with Sl Required, Rev. 5 3-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 9 3-ES-1.4, Transfer to Hot Leg Recirculation, Rev. 2 3-LOOP-1, Loss of Offsite Power after Sl, Rev. 2 3-RO-1, Balance of Plant Operator Actions During Use of EOPs, Rev. 4 3-SOP-CC-001A, Component Cooling System Operation - Filling, Venting and Draining, Rev. 20 3-SOP-EL-001, Diesel Generator Operation, Rev. 48 3-SOP-EL-005A, 480 Volt Electrical System Operation, Rev. 12 3-SOP-EL-015, Operation of Non-Safeguards Equipment During Use of EOPs, Rev. 21 3-SOP-RW-002, Intake Structure Operation, Rev" 26 3-SOP-RW-005, Service Water System Operation, Rev. 36 3-SOP-Sl-001, Safety Injection System Operation, Rev. 48 Attachment Preventive Maintenance and Inspections
- 0-GNR-410-ELC, Emergency Diesel Generator
- 8-Year Inspection, performed
- 319111 0-GNR-412-ELC, Emergency Diesel Generator
- 16-Year Inspection, performed
- 319111 0-MTR-401-ELC, lnspection/Repair and Overhaul of Motors 480 Volt or Lower (23 CCW Pump), performed
- 26112 0-MTR-401-ELC, lnspectionlRepair and Overhaul of Motors 480 Volt or Lower (32 Sl Pump), performed
- 7l10lO8 0-SCR-401-GEN, lntake Structure Trash Rack lnspection and Cleaning, performed
- 6112112 0-STR-401-SWS, Service Water Strainers Inspection/Overhaul, performed
- 1l22l10 2-PMP-008-CCW, lnspection/Repair of the CCW Cooling Pump, performed
- 10/6/09 2-PT-M032, Condenser Pit Flood Alarms, performed
- 9113112 3-GNR-021-ELC, Emergency Diesel Generator
- 4-Year Inspection, performed
- 4l2AnA 3-IC-PC-l-P-33DLO, Diesel Generator No. 33 Lube Oil Pressure, performed
- 917111 3-PT-A029C, 33 EDG Underground
- FOST Leak Test PressA/aclUT
- Method, performed
- 27112 3-PT-M108, RHR/SI/CS
- System Venting, performed
- 1014112 EN-f&C-Pressure Switch PM Basis Template, dated
- 12117107
- EN-Pump-Vertical
- PM Basis Template, dated
- 5126108
- EN-Refay-Control
- PM Basis Template, dated
- 2114112 H-6846-02, Unit No. 3 Service Water Scanning Sonar lnspection Report, dated
- 9114112 lC-PC-f-L-12065, Diesel Generator Fuel Oil Storage Tank No. 33 Level, performed
- 2l2l$8 PR. No.32-282,
- EDG 33 Jacket Water Cooler Eddy Current Preliminary Report, dated
- 8127112 PR. No.32-283,
- 8127112
- SEP-SW-001
- GL 89-13 Inspection, performed
- 27112 Preventive Maintenance Basis Template, Valve - Air Operated (AOV), Rev. 1 Preventive Maintenance Basis Template, Valve - Motor Operated (MOV), Rev. 0 Preventive Maintenance Basis Template, Valve - Heat Exchanger - General Tube Type, Rev. 2 Procedures
- 0-CY-2510, Closed Cooling Water Chemistry Specifications and Frequencies, Rev. 13 0-CY-3335, Monitoring Closed Cooling Water Using Ammonia Test Strips, Rev. 0 2-PT-M032, Condenser Pit Flood Alarms, Rev. 8 2-PT-R084A,21
- EDG 8 Hour Load Test, Rev. 16 2-PT-M1-4, ECCS Monthly Alignment Verification, Rev. 4 2-VLV-001-AOV, Fisher 10" Butterfly Valve Maintenance for
- VS-PCV-1 190, 1191 , 1192, Rev. 3 3-BKR-004-ELC, Inspection, Lubrication, and Testing of Westinghouse
- 480 Volt
- DS-416 and
- DS-840 Breaker, Rev.46 3-BKR-016-CUB, Westinghouse
- 480V Switchgear Cubicle Inspection and Cleaning, Rev. 9 3-BKR-017-ELC, Current Sensor and/or Trip Unit Replacement, Setting and Testing, Rev. 9 3-COL-CC-1, Component Cooling System, Rev. 28 3-lC-PC-l-F-625, Reactor Coolant Pump Thermal Barrier Component Cooling Header Flow, Rev.11 3-PMP-012-SWS, Service Water Pump Removaland lnstallation, Rev. 16 3-PT-R003A,l, Safety Injection Recirculation Switch 4 Test, Rev. 4 3-PT-R160C, 33 EDG Capacity Test, Rev. 11 3-PT-M108, RHR/SI/CS
- System Venting, Rev. 15 3-VLV-052-RCS, Pressurizer
- PORV Inspection and Overhaul, Rev. 5 3-VLV-060-AOV, Fisher 10" Butterfly Valve Maintenance for
- VS-PCV-1190, 1191, 1192, Rev. 6 Attachment
- EN-DC-324, Preventive Maintenance Program, Rev. 8
- EN-DC-335, Preventive Maintenance Basis Template, Rev. 3
- EN-LI-100, Process Applicability Determination, Rev. 12
- EN-Ll-101, 10
- CFR 50.59 Evaluations, Rev. 9
- EN-MP-112, Shelf Life Program, Rev. 4
- EN-MP-125, Control of Material, Rev. 8
- EN-OP-119, Protected Equipment Postings, Rev. 5lP-EP-120
- 9.1 , Category 8.0 Hazards Emergency Action Levels, Rev. 6lP-EP-AD13
- 2, EAL Technical Bases, Rev. 12
- SEP-CV-IP-002, IPEC Check Valve lmplementation Program, Rev. 0 SEP-lP3-lST-1, Inservice Testing Program Basis Document, Rev. 0
- SEP-SW-001, NRC Generic Letter 89-13 Service Water Program, Rev. 6
- VSR-P-O15-A, Safety and Relief Valve Set Pressure Testing, Rev. 10 Vendor Technical Manuals 8M-1011, Jacket Water Cooler Heat Exchanger Specification Sheet, dated
- 11121167 13-100000000, Six 2450 HP Diesel Engines for AC Generator Drive Model16-251-El Vendor Technical Manual, Rev. 33 047-36095, 26APK-1 (Pump Tag
- SWP-34) Pump Curve, dated
- 4118189 209-100000314,26
- APK-1 Service Water Pumps Vendor Manual, Rev. 0 304-100000541, 1P Unit 3 Safety lnjection Pumps Operating and Maintenance Instructions Vendor Manual. Rev. 17 1059, lnstructions for lnstallation, Operation, and Maintenance of "S" Line General Service Pumps Vendor Manual, Rev. 5 Alyoco Manual Number 1429, Gate Globe and Swing Check Valves, Rev. 2 Curve No. 46060, Component Cooling Pump No. 23 Pump Curve, Rev. 0 Goulds Pumps ModelVlT Installation, Operation, and Maintenance, Rev. 0
- HS 3481 ,2y2JTCH (32 Sl Pump Curve), dated
- 1119198 Ingersol Dresser Pump Certified Pump Curve 050-33168.01
- LTR-EMPE-04-9, Westector Test Procedure, Rev. 1 NYPA 116-100000156, Crane Motor Operated Gate Valve Maintenance Manual, Rev. 0 Schulz Electric Co., Document Package for Entergy Nuclear lndian Point 3, Purchase Order Number
- 4500553672
- Line ltem 00001, 350 HP AC Westinghouse Motor Serial/lD Number 33-72, Job No. N-2595,
- 04104107
- VM 1418, lnstruction Manualfor Anchor Darling Motor Operated Gate Valves, Rev. 4
- VM 1512, Fisher Controls Company Type 9200 T-Ring Butterfly Valve Bodies, Volume 3 of 7
- VM 1512, Fisher Controls Company Type 486U Actuators, Volume 5 of 7
- VM-2351, ALCO lnstruction Manual, Rev. 1-1\ffM 13-100000000, Six2450 HP Diesel Engines for AC Generator Drive Model 16-251-E1 Attachment
Work Orders
- 00123920
- 00130508
- 00223281
- 00249679
- 00274658
- 00287109
- 00305264
- 51451679
- 51453490 AC ADAMS AEC AFW AMSAC ARP ASME ATWS CAP ccw CDBI CFR CR CW DBA DBD DC DRS DRP ECCS EDG EOP GL GPM HELB HX tMc IN IP rsT JW LERF LHSI A-13
- 51480140
- 51796053
- 51496408
- 51796062
- 52216541
- 51800341
- 52310227
- 52193601
- 52388706
- 52202017
- 52446277
- 52222530
- 00184367
- 52288906
- 51285668
- 52293056
- 51679770 52301368
LIST OF ACRONYMS
52302643 52309658 52435016 52437012 52440865 52442518 Alternating
Current Agencywide
Documents
Access and Management
System Atomic Energy Commission
Auxiliary
Feed Water Anticipated
Without Scram Mitigation
System Actuation
Circuitry Alarm Response Procedure American Society of Mechanical
Engineers Anticipated
Without Scram Corrective
Action Program Component
Cooling Water Component
Design Bases lnspection
Code of Federal Regulations
Condition
Report Circulating
Water Design Basis Accident Design Basis Document Direct Circuit Division of Reactor Safety Division of Reactor Projects Emergency
Core Cooling System Emergency
Diesel Generator Emergency
Operating
Procedure Generic Letter Gallons per Minute High Energy Line Break Heat Exchanger lnspection
Manual Chapter Information
Notice Inspection
Procedure In-Service
Test Jacket Water Large Early Release Frequency Low Head Safety Injection Attachment
- LO [[]]
- LOCA [[]]
- TE [[]]
- MOV [[]]
- MSIV [[]]
- MSLB [[]]
- NCV [[]]
- NPSH [[]]
- NRC [[]]
- OE [[]]
- PM [[]]
- PORV [[]]
- PRA [[]]
- PSID [[]]
- RAW [[]]
- RCS [[]]
- RHR [[]]
- RPV [[]]
- RRW [[]]
- SI [[]]
- SSC [[]]
- SPAR [[]]
- SRV [[]]
- SST [[]]
- ST [[]]
- SW [[]]
- TS [[]]
- UFSAR [[]]
VAC VDC A-14 Lube Oil Loss-of-Coolant
Accident Load Tap Changer Maintenance
and Test Equipment Motor Operated Valve Main Steam lsolation
Valve Main Steam Line Break Non-cited
Violation Net Positive Suction Head U.S. Nuclear Regulatory
Commission
Operating
Experience
Preventive
Maintenance
Power Operated Relief Valve Probabilistic
Risk Assessment
Pounds per Square Inch Differential
Risk Achievement
Worth Reactor Coolant System Residual Heat Removal Reactor Pressure Vessel Risk Reduction
Worth Safety Injection Structure, System, and Component Standardized
Plant Analysis Risk Safety Relief Valve Station Service Transformer
Surveillance
Test Service Water Technical
Specifications
Updated Final Safety Analysis Report Volts, Alternating
Current Volts, Direct Current Attachment