ML11292A198

North Anna, Units 1 and 2, Response to Request for Additional Information Restart Readiness Determination Plan

ML11292A198
Person / Time
Site:	North Anna
Issue date:	10/18/2011
From:	Grecheck E S Virginia Electric & Power Co (VEPCO), Dominion
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
11-566B
Download: ML11292A198 (28)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 10 CFR 100, Appendix A October 18, 2011 U.S. Nuclear Regulatory Commission Attention:

Document Control Desk Washington, DC 20555 Serial No.: NL&OS/ETS Docket Nos.: License Nos.: 11-566B R1 50-338 50-339 NPF-4 NPF-7 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

NORTH ANNA POWER STATION UNITS 1 AND 2 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION RESTART READINESS DETERMINATION PLAN By letters dated September 26, 28 and 30 and October 6, 2011, the NRC requested additional information (RAI) regarding Dominion's Restart Readiness Determination Plan for North Anna Power Station following the August 23, 2011 Central Virginia earthquake.

By letters dated September 27, 2011 (Serial Nos. 11-520A and 11-544), October 3, 2011 (Serial Nos. 11-544A and 11-566), and October 10, 2011 (Serial Nos.11-566A and 11-577), Dominion responded to a number of the RAI questions provided by the NRC technical review branches.

In the attachment to this letter, Dominion is providing responses to several of the remaining questions, as well as clarifications requested by the NRC staff on previously submitted responses.

The specific technical review areas and the associated questions being answered are provided below for reference:

Electrical Instrument and Control Steam Generators Reactor Vessel Internals Clarifications for Questions 1, 2, and 3 Clarifications for Questions 1, 2, and 3 Supplemental Questions 1 and 2 Clarifications for Questions 1, 2, and 4 Responses to the remaining unanswered RAI questions will be provided in subsequent correspondence.

Serial Number 11 -566B Docket Nos. 50-338/339 Page 2 of 3 If you have any questions or require additional information, please contact Thomas Shaub at (804) 273-2763 or Gary D. Miller at (804) 273-2771.Sincerely, E. S. Grecheck Vice President

-Nuclear Development

Enclosure:

Response to Request for Additional Information

-Restart Readiness Determination Plan (with Attachment)

There are no commitments made in this letter.COMMONWEALTH OF VIRGINIA COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by E. S. Grecheck who is Vice President

-Nuclear Development, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document on behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.Acknowledged before me this B day of ..n0L1 , 2011.My Commission Expires: "!A!f !2o1 .Ginger Lynn Rutherford NOTARY PUBUC -- N ry Public Commonwealth of Virginia Reg. # 310847 My Commission Expires 4/30/2015 Serial Number 11-566B Docket Nos. 50-338/339 Page 3 of 3 cc: U.S. Nuclear Regulatory Commission

-Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, Georgia 30303-1257 NRC Senior Resident Inspector North Anna Power Station M. Khanna NRC Branch Chief- Mechanical and Civil Engineering U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9E3 11555 Rockville Pike Rockville, MD 20852-2738 R. E. Martin NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 11555 Rockville Pike Rockville, MD 20852-2738 P. G. Boyle NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 11555 Rockville Pike Rockville, MD 20852-2738 J. E. Reasor, Jr.Old Dominion Electric Cooperative Innsbrook Corporate Center 4201 Dominion Blvd.Suite 300 Glen Allen, Virginia 23060 Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Enclosure Response to Request for Additional Information Restart Readiness Determination Plan Virginia Electric and Power Company (Dominion)

North Anna Power Station Units I and 2 Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 1 of 17 BACKGROUND By letters dated September 26, 28 and 30 and October 6, 2011, the NRC requested additional information (RAI) regarding Dominion's Restart Readiness Determination Plan for North Anna Power Station following the August 23, 2011 Central Virginia earthquake.

By letters dated September 27, 2011 (Serial Nos. 11-520A and 11-544), October 3, 2011 (Serial Nos. 11-544A and 11-566), and October 10, 2011 (Serial Nos.11-566A and 11-577), Dominion responded to several of the RAI questions provided by the NRC technical review branches.

In this letter, Dominion is providing its responses to several of the remaining questions, as well as clarifications requested by the NRC staff on previously submitted responses.

NRC REQUEST FOR INFORMATION Electrical During a conference call between the. NRC and Dominion personnel on October 6, 2011, the NRC requested clarification of Dominion's responses to Electrical Questions Nos. 1, 2, and 3 and Instrument and Control (I&C) Questions 1, 2, and 3 that were provided in Dominion's October 3, 2011 letter (Serial No.11-566). The requested information for Electrical Questions 1, 2 and 3 and a clarification of station and EDG battery testing are provided below.Requested Clarification

-Electrical Question I Show results of previous calibrations of electrical equipment (e.g., UV/DV relays) and compare to post earthquake results to provide evidence that equipment was not affected by earthquake.

Dominion Response The undervoltage (UV)/degraded voltage (DV) relays were calibrated post earthquake and compared to previous calibration data for the relays and timers. The data is provided as an attachment to this letter. Based on the results of the detailed inspections of the electrical components and the recent calibrations of the Unit 1 and 2 UV/DV relays, there is reasonable assurance that the August 23, 2011 earthquake did not result in any seismically induced damage or cause any hidden damage to the Unit 1 and Unit 2 UV/DV relays such that their safe shutdown functions would be prevented from being performed.

Requested Clarification

-Electrical Question 2 Provide detailed justification why inspections of Unit 2 are adequate to demonstrate functionality/operability of electrical and /&C equipment post earthquake for Unit 1.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 2 of 17 Dominion Response The electrical equipment (e.g., batteries, bus work, breakers) and I&C equipment (e.g., protection and control cabinets) in Unit 1 and Unit 2 are similar and functionally equivalent and the equipment orientation and location is the same in each unit. Thus, the effect of the seismic event on Unit l's electrical and I&C equipment were the same as the effect on the electrical and I&C equipment tested in Unit 2. Based on the equivalency and orientation of the equipment, the inspections of Unit 2 electrical and I&C equipment are adequate to demonstrate functionality/operability of electrical and I&C equipment in Unit 1.In addition, as noted in the Clarification to I&C Question 2 below, surveillances, including calibrations and functional tests, have been performed on the Unit 1 and 2 electrical and I&C equipment to confirm operability.

For the equipment that cannot be tested in the current plant conditions, surveillance tests will be performed as Units 1 and 2 move from the current mode to power operations as required by the Technical Specifications.

Requested Clarification

-Electrical Question 3 Will Dominion perform additional inspections on the electrical systems on Unit 1 when the Unit is shutdown for refueling?

Dominion Response Inspections similar to the inspections performed on Unit 2 emergency switchgear, documented in Dominion letter dated October 3, 2011 (Serial No.11-566), will be performed on the Unit 1 "J" Emergency Switchgear Bus during the next refueling outage. The maintenance will include visual inspections of the hardware and fasteners of breaker cubicles, break-a-way torque verifications on bus bars, and check bus connections by performing resistance readings.

In addition, normally required refueling outage surveillances will be completed on electrical busses as required by the Technical Specifications.

Additional Information -Station and EDG Battery Testing Dominion Response In a letter dated October 3, 2011 (Serial No.11-566), Dominion provided information regarding the testing of the Station and EDG batteries.

The following information provides a clarification of the actual test performed on the batteries and the results of the post earthquake Station and EDG Battery testing.The station batteries are tested using a "modified performance discharge test" and the EDG batteries are tested using a "performance discharge test," consistent with Technical Specification SR 3.8.4.9.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 3 of 17 Comparison of battery reliability pre and post August 23, 2011 earthquake:

Battery cell parameters have been measured for the safety related seismically qualified 125VDC emergency bus station batteries and emergency diesel generator (EDG)batteries.

Battery cell parameters were also measured for non-safety related and non-seismic batteries for the station blackout (SBO) diesel generator and the technical support center (TSC). The SBO and TSC batteries are not installed in seismic racks and therefore were not restrained from motion during the seismic event. No damage or tipping occurred to any of the non-seismic batteries.

Cell parameters for the above batteries are measured quarterly.

The cell parameters measured include cell voltage, specific gravity, temperature, and level as well as overall terminal voltage and visual inspections of the cells. No abnormal or unusual changes have been identified for any of the battery cell parameters measured post earthquake when compared with data from before the earthquake.

Focused civil and electrical engineering inspections have been performed post earthquake.

The issues identified during the walkdowns have been dispositioned and do not have a detrimental impact to the ability of the safety related batteries to perform their safe shutdown functions.

Thermography was performed post earthquake on the batteries with no abnormal indications noted.Capacity testing of the Unit 2 safety related batteries was performed during the refueling outage. Testing was performed as required by the station's Technical Specifications.

The 2-1, 2-11, 2-111, and 2-IV 125VDC emergency bus batteries were modified performance discharge tested. The 2H and 2J EDG batteries were performance discharge tested. Both test options are permitted by the Technical Specifications.

The difference between a modified performance and a performance discharge test is only during the first minute of a modified performance discharge test where the highest rate of the battery's design duty cycle is applied. The IEEE recommends that testing consistency be maintained during a battery's lifetime to aid in trending the battery's capacity over its lifetime.

In the case of the 125VDC emergency bus batteries, modified performance discharge testing has been performed and performance discharge testing has been performed on the EDG batteries since installation.

The following inspections and tests were performed to verify the operability of the safety related batteries:

• cell parameter readings for seismic and non-seismic batteries, and the following tests and inspections," Unit 2 capacity testing results (included in the table below for the Unit 2 batteries)," detailed inspections of both units' batteries, and* similar location and orientation of both units' batteries.

Based on the results of the post earthquake battery test and inspections, there is reasonable assurance that the August 23, 2011 earthquake did not result in any seismically-induced damage or cause any hidden damage to the Unit 1 and Unit 2 Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 4 of 17 station and EDG batteries such that their safe shutdown functions would be prevented from being performed.

Unit 2 Battery Test Results Station Battery Installation Dates Battery Installation Date 1-1 Station battery bank Fall RFO 2001 1-11 Station battery bank Spring RFO 2003 1-111 Station battery bank Spring RFO 2003 1-IV Station battery bank Fall RFO 2004 1 H EDG battery bank Fall RFO 2007 1J EDG battery bank Fall RFO 2007 2-1 Station battery bank Fall RFO 2002 2-11 Station battery bank Fall RFO 2002 2-111 Station battery bank Spring RFO 2004 2-IV Station battery bank Spring RFO 2004 2H EDG battery bank Spring RFO 2007 2J EDG battery bank Spring RFO 2007 SBO diesel generator battery August 2008 Technical Support Center battery November 2008 Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 5 of 17 Instrument and Control During a conference call between the NRC and Dominion personnel on October 6, 2011, the NRC requested clarification of the Dominion responses to Electrical Questions Nos. 1, 2, and 3 and I&C Questions 1, 2 and 3 that were provided in Dominion's October 3, 2011 letter (Serial No.11-566). The requested information for I&C Questions 1, 2, and 3 is provided below.Requested Clarification

-/&C Question 1 RCE concluded that the detectors may have shifted during earthquake.

Demonstrate that the Nuclear Instrumentation is properly aligned/installed.

Dominion Response The nuclear instrumentation is located in a well inside the neutron shield tank, which surrounds the reactor vessel. The bottom of the detector is rigidly supported which prevents movement.

The upper portion of the detector is not rigidly supported and could have moved during the seismic event, but the well is 1/4 inch in diameter larger than the nuclear instrument, allowing very little area for the instrument to move. If movement occurred, it would have only been during the event. Post event the detector would have returned to its normal position.

The nuclear instrumentation was satisfactorily calibrated during the unit shutdowns.

Testing of the Unit 1 and Unit 2 power range detectors was completed prior to the earthquake and again during the current outages, with the data analyzed by Char Services, LLC. The testing included insulation resistance measurements, capacitance, time domain reflectometry, and shutdown current-voltage characteristic curves. No anomalies were noted between the test data obtained prior to the earthquake and the data obtained after the earthquake.

Before reactor startup of either unit, the high power trip setpoints for the power range nuclear instrumentation will be set conservatively low until core analysis can confirm proper response of the detectors.

To ensure proper response of the reactor core and proper adjustment of nuclear instrumentation, Unit 1 will hold reactor power at < 30% power to perform core flux mapping. Unit 1 will also hold reactor power at < 75% and < 96% power to validate proper core response and adjust nuclear instrumentation as necessary.

Unit 2 will follow the normal plant ascension testing for a refueling outage, which includes holding reactor power at < 30%, < 75%, and < 96% power to perform core flux mapping and validate proper core response and adjust nuclear instrumentation as necessary, similar to Unit 1.Requested Clarifications

-/&C Question 2 Will Dominion perform specific hold points with specific criteria for evaluating the plant control systems during the startup of the units? E.g., S/G level control, EHC, etc.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 6 of 17 Dominion Response A Restart Readiness Procedure has been developed which will delineate the plant evaluation criteria, prior to and during the Unit 1 and Unit 2 restart from Mode 4 entry to full power steady state operation.

This procedure includes:* Formal Startup Assessment prior to Mode 4 entry" Staff and senior management augmentation during the restart" Operations staff training and readiness" Validation of NRC commitment completion

• Augmented assessment of plant equipment as it is returned to service* Evaluation of the core and nuclear instrumentation response at various power level holds (< 30%, < 75%, < 96%)* Engineering readiness evaluation and performance checks of components and systems Included as part of the Readiness Restart Procedure are: Management Determined Increased Monitoring and Oversight Requirements, Required System Mode Change Readiness Checklists, Required System Performance Reviews, and Program Review Checklists.

The Management Determined Increased Monitoring and Oversight Document identifies the areas that have been determined to require additional attention during the plant startup and includes activities, such as: " Augmented equipment monitoring

-e.g., vibration, thermography and predictive maintenance" Equipment/component walkdowns following equipment startup -compare existing data with previous data to identify any potential abnormal conditions

• Monitoring of turbine during startup* Increased monitoring of reactor physics testing, power changes and RCS activity during reactor startup and power increase to 100%The Required System Readiness Mode Change Checklists and Performance Reviews are completed by the systems engineers after completing system walkdowns, which documents the physical condition of the system. Conditions Reports are reviewed and resolved, as necessary, for each mode change. The following are some examples of areas and attributes of the system engineers' walkdowns:

Material Condition-Pump and fan vibrations and noise-Valve packing, stems and operators-Air Operated Valves/Solenoid Operated Valves Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 7 of 17 Insulation damage and discoloration Structural weld condition Hangers and supports Corrosion Fluid leaks Elastomer components Equipment foundations/supports" Passive Design Protection

-Flood/Fire Barriers-Seismic-High Energy Line Breaks" Configuration Management

-Temporary Modifications -jumpers, hoses, cooling, etc.-Existing Conditions

-scaffolding, ladders, welding or grinding etc.In addition, the Program Review Checklists require the program owners to review the programs (e.g., pumps and valves, MOVs & AOVs, Appendix J, Appendix R, heat exchangers, transformers, etc.) to ensure program requirements are met for mode changes.Requested Clarifications

-I&C Question 3 Do we plan to increase surveillance test frequency for the electrical and W&C equipment after startup to detect hidden damage that might occur after some period of operation.

Dominion Response Following the August 23, 2011 earthquake, a sampling of electrical connections was inspected in detail for damage. Electrical connections for the Reactor Protection System (RPS), Rod Control System, and Emergency Power Buses were inspected.

In the RPS, Unit 2 Loop A, B and C Feedwater Control System calibrations were performed.

During these calibrations, electrical connections are tested to ensure they are in proper working order. None of the calibrations or subsequent performance tests (PTs) found any indication of a loose or damaged connection.

In the Rod Control System, the Unit 1 Rod Control System Maintenance with the Reactor Trip Breakers Open calibration was performed.

The function of the logic cabinet circuit cards is tested. During this testing, the electrical connections were checked and proper seating of the circuit cards was ensured. Maintenance and inspection was performed on the 2J Emergency Switchgear Bus (4160 V bus). This procedure ensures proper electrical connections through bus/cubicle inspection, insulation resistance testing, and micro-resistance readings of the bus-to-bus bolted connections and proper torque of the electrical connections.

Many other electrical tests have also been performed on both Unit 1 and Unit 2 wherein electrical connections are tested with a functional test. There have been no loose Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 8 of 17 connections identified during the testing or inspections performed since the earthquake.

Visual inspections internal to emergency electrical and electrical power system components (breakers, process racks, etc.) were performed for the electrical systems.Visual inspection did not identify areas of connection distress or loose components.

In addition, the station's on-going thermography program has not identified any increase in loose connections following the seismic event.The applicable Instrument Calibration Procedures (ICPs) were performed for the Reactor Trip System (RTS) and the Engineered Safety Features Actuation System (ESFAS) on Unit 1 and are planned to be completed prior to restart on Unit 2. These ICPs require the calibration/operability verification of the instruments within the loop.The performance of the procedures require calibration/verification of the loop transmitter(s)/remote sensor(s), active/adjustable 7300 circuit cards, indicator(s), recorders, and the check of control room alarms, trip status, computer points, and channel test/bistable test switches.

In addition to the loop calibrations, functional testing of the RTS and ESFAS was performed (normally done each refueling outage) to ensure proper system actuation upon receipt of RTS/ESF signals. Further details of the extensive calibrations and functional testing are detailed in Dominion's letter dated October 3, 2011 (Serial No.11-566).Therefore, the current surveillance requirements and associated frequencies of the Technical Specifications and the Technical Requirements Manual, as well as programmatic requirements, will ensure the continued operability of electrical and I&C equipment.

Any post restart condition reports will continue to be considered for potential earthquake damage. If the conditions reports show any increased failure rates attributable to the seismic event, the normal corrective action process will drive an extent of condition review and initiate additional testing as required.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 9 of 17 Steam Generators (S/Gs)In an NRC letter dated October 6, 2011 supplemental questions were asked regarding the S/G inspection results for Units 1 and 2.Requested Clarifications

-Steam Generator Question I

Reference:

Dominion letter 1 1-520A, September 27, 2011, Attachment 1, Page 19 of 25 For the UT thickness measurements taken in the "A" SIG feedring, it was stated that "the thickness measurements obtained exceeded the minimum design requirement of 0.350 inch." Please describe the following, as they relate to the analysis of the minimum thickness design requirement for the feedring:

the minimum/maximum interval between UT inspections, the assumed wear rate for the design requirement, and conservatisms associated in the design requirement.

It is also stated that "A re-analysis of the allowable wall thickness was performed....

This analysis concluded that the allowable minimum wall thickness for localized degradation is 0. 240 inch." Please provide the re-analysis that led to the reduction in the minimum allowable wall thickness.

Also, describe the differences between the new re-analysis and the original minimum design requirement analysis.

Also justify that the reduced minimum wall thickness of 0.240 inch will provide reasonable assurance that in the interval until the next UT inspection, wear in these regions will not pose a safety or radiological hazard.Dominion Response Ultrasonic (UT) thickness measurements were taken in selected regions of the S/G "A" feedring during this outage for the purpose of monitoring flow assisted corrosion (FAC)related degradation.

Previous measurements were taken in 2001, and 2007. When factoring in the results from the 2011 inspections, the maximum FAC rate occurred in the left side reducer extension, and over the ten year measurement period, was 0.005 inch per year. The next feedring UT examination is planned for the spring 2015 refueling outage which is approximately 3.5 years from the current outage. Assuming that this rate of degradation continues through the spring 2015 outage, an additional 0.018 inch reduction in the thickness of the left side reducer extension would be expected (i.e., 3.5 years x 0.005 inch per year).The maximum apparent FAC rate for the period from 2007 through 2011 is 0.025 inch per year (at the local thin spot). However, the minimum 2011 measurement (0.350 inch)was likely taken at a different location than those taken during 2001 and 2007.Consequently, the growth rate implied by these measurements (0.025 inch per year) is likely overly conservative.

This observation is supported by the visual examinations of J-nozzles which identified no evidence of FAC advancement at the J-nozzle/feedring interfaces.

Nonetheless, if it assumed that the FAC rate of this minimum location advances at a rate of 0.025 inch per year until the spring 2015 outage, the remaining Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 10 of 17 thickness at this location would be 0.263 inch (i.e., 0.350 -(3.5 x 0.025) = 0.263), indicating ample margin to the minimum allowable thickness for localized degradation (0.240 inch).The reanalysis of allowable local wall thickness is Westinghouse Proprietary and is based on a feed line break (most limiting faulted condition).

A finite element model was created for the 10 inch Schedule 80S (Extra Strong) feedwater ring. A section of the feedwater ring was assumed uniformly degraded over 60 degrees of the feedwater ring circumference.

This bounded the local degradation identified by UT thickness measurements.

Based on the expected wear rate discussed above, the degradation will remain above 0.240 inch.Requested Clarifications

-Steam Generator Question 2

Reference:

Dominion letter 11-566A, October 10, 2011, Attachment 1, Page 8 of 22 Provide a summary of the eddy current inspection results for Unit 2 SIG A and C, similar to that provided in Dominion letter I 1-520A (September 27, 2011) on page 18 of 25 of Attachment

1. For example, how many tubes with indications were found, what kind of indications, and did they show significant change relative to previous inspections.

Indications refer to indication of wall loss and dings/dents. (Page 9 of 22 already states that eddy current identified no evidence of foreign objects or foreign object wear.)Dominion Response Prior to this outage, tube support plate (TSP) wear was the only degradation mechanism classified as "existing" in the North Anna Unit 2 SIG tubing. Several other mechanisms were classified as "potential" (i.e., anti-vibration bar (AVB) and foreign object wear, pitting within top-of-tubesheet sludge region, and hot leg top of tubesheet intergranular assisted (IGA)/outside diameter stress corrosion cracking (ODSCC) within the sludge pile region). It is primarily these damage mechanisms that were targeted by this inspection.

While tube denting is not classified as a degradation mechanism, there was particular interest in the potential for any new tube denting that may have been caused by the August 23, 2011 seismic event. The Unit 2 "A" and "C" S/G inspection scope included the performance of miscellaneous rotating probe inspections for dents (which includes dings) that included the identification of any new dents, as well as an inspection of any previous dents that were > 5 volts regardless of their location.

The rotating pancake coil (RPC) inspections did not identify any dents in the Unit 2 "A" and "C" S/Gs, and there was no evidence of change in the previously identified dents.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 11 of 17 Reactor Vessel Internal (RVI) Components In an October 14, 2011 phone call, the NRC staff requested additional clarification of the reactor vessel internals.

Requested Clarifications

-CVIB Question I Discuss the criteria used for determining functionality of reactor internals, core support structures, and mechanical equipment other than those verified to be functional based on performance of Inservice Testing. Discuss how your criteria would identify possible hidden damage that could not be observed from visual inspection.

Dominion Response The components of the reactor internals whose functionality are verified by surveillances or inservice testing include the control rod guide tubes, the core exit thermocouples, the reactor vessel level instrumentation, and incore flux monitoring bottom mounted instrumentation.

Other portions of the reactor internals structures perform their safety related functions in a purely passive manner. The safety functions performed by such passive structures may be summarized as:* Structural support (vertical and lateral) of the core for the design basis loads* Guiding coolant flow to ensure even distribution to the core inlet and from the core to the vessel outlet nozzles" Limiting the small bypass flows that do not directly cool the core These functions are achieved by the internals as a whole or by its subassemblies.

The criterion that ensures that the passive structures perform these safety functions is that, considered as an assembly, the reactor internals retain its overall structural integrity.

Although the reactor internals can withstand some damage without impacting its structural integrity, one measure of structural integrity is an absence of damage.The inspections that were able to be performed on the reactor internals directly addressed the three safety functions above. The inspections performed, detailed in Dominion's October 10, 2011 (Serial No. 11-566A), correlate with the three areas of design function as noted below: " Structural Support: upper and lower support columns, upper core support plate keyways, upper and lower fuel alignment pins" Coolant Guidance:

baffle plates and baffle former bolts 0 Limiting Bypass: baffle plate edge gaps Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 12 of 17 These inspections together with the several other inspections confirmed an absence of damage to the reactor internals from the seismic event, and are therefore verification that structural integrity of the reactor internals assembly is maintained such that the safety functions will be performed as designed.

As noted in the October 10, 2011 submittal, both MRP-227 and EPRI NP-6695 employ a leading indicator and sampling approach to detect aging effects (MRP-227) and damage (NP-2295) and thereby conclude the overall condition of the component.

If there is no damage to the items inspected, then it is reasonable to conclude that no significant damage is present on uninspected items. For example, if no damage is seen to baffle former bolts then it is reasonable to assume no damage to core barrel former bolts. The acceptability of this approach is further assured by the recognition that the design of the reactor internals is inherently conservative and redundant such that significant damage would have to exist to present a challenge to performance of safety functions.

For example, there are six core barrel radial supports (not directly observed in the recent inspections) that redundantly prevent excessive deflection of the core barrel. Damage to one of these would not prevent achievement of the intended safety function.As described in Enclosure 3 of Dominion's September 17, 2011 letter (Serial No.11-520) another criterion for concluding no damage to the unobserved portions of the reactor internals is the conclusion by the NSSS vendor that the August 23, 2011 earthquake caused stresses that were bounded by Operating Basis Earthquake (OBE)(no yield) criterion.

Therefore, the event was not of a magnitude that could have caused significant damage to the unobserved reactor internals structures.

Finally, it is worth noting that final assembly of the reactor and functional checks performed during reactor startup provide additional confirmation of the overall integrity of the reactor internals assemblies.

.Each refueling outage the upper internals are removed and then re-installed in the reactor to facilitate refueling.

Any distortion of the assemblies due to unseen damage would likely be evident at the time of assembly by issues such as interferences and binding. No distortion was identified during the re-assembly of the Unit 2 RVIs.In summary, the passive safety functions of the reactor internals, performed in part by components not directly observed by inspections, is verified by confirmation of overall structural integrity of the assemblies.

The overall integrity is evidenced by lack of damage in observed components, the moderate level of the seismic event as confirmed by the NSSS vendor, the redundancy of reactor design for achieving safety functions, and the lack of distortion as evidenced by the absence of reassembly issues.Requested Clarifications

-Reactor Vessel Internals Question 2 The licensee, in Attachment I 1-566A of the October 10, 2011 submittal stated that it did not identify any degradation in the RVI components during the latest inspections at North Anna Unit 2. To ensure that the effect of seismic loading on the RVI components Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 13 of 17 did not [propagate]

1 any cracking in any un-inspected regions, the staff decided to issue another follow-up request for additional information (RAI) which are addressed below." The staff believes that the inspections performed by the licensee are similar to those recommended in the guidelines specified in the MRP-227, "Pressurized Water Reactor Internals Inspections and Evaluation Guidelines," with the following exceptions:

(1) the inspections of some of the "Primary" components addressed in MRP-227, e.g., upper core barrel flange weld, baffle-edge bolts, baffle-former assembly, thermal shield flexures and internal hold-down spring were not performed and (2) the inspection methodology is not consistent with MRP-227, for example ultrasonic testing (UT) is recommended for baffle-former bolts per MRP-227, whereas the licensee performed visual testing (VT-3) inspections which may not adequately identify the extent of cracking.

The licensee is requested to provide an explanation for not inspecting the afore-mentioned "Primary" components." The licensee, in Attachment 11-566A of the October 10, 2011 submittal indicated that IASCC was not expected to be a prevalent preexisting condition based on results for previous UT examinations of baffle-former bolts in other PWRs. Provide a quantitative estimate of the expected remaining margin of uncracked baffle-former bolts in the North Anna RVI, taking into account the expected percentage of bolts with IASCC, the differences in bolt material from other PWRs that performed UT examinations, the results and limitations of the VT-3 examination performed at North Anna, the required minimum bolting patterns or numbers for North Anna Units 1 and 2, and any other relevant factors.Dominion Response As noted in the referenced submittal, the inspection requirements in MRP-227 are specific to management of potential long term aging effects and must necessarily be modified if it is to be used for detection of earthquake damage effects. Also noted is the fact that MRP-227 uses a leading indicator approach and sampling of redundant items to make an assessment of the overall condition of the reactor internals.

The condition assessment based on the items inspected under MRP-227 applies to the remainder of the reactor internals that are not inspected.

This overall approach taken by MRP-227 for aging is similar to the approach taken in EPRI NP-6695 for seismic events: certain components and systems considered to be seismically sensitive, i.e., leading indicators of seismic damage, are inspected and if no significant damage is detected then the condition assessment is considered applicable to the larger population.

If significant damage is detected then expanded scope inspections are performed.

1 Originally "initiate".

As clarified by telecon, the question is in regard to propagation of potential pre-existing cracks, not initiation of new cracks due to the earthquake.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 14 of 17 The approach taken in the inspections of the North Anna Unit 2 reactor internals for earthquake damage was therefore, similar in approach and intent as MRP-227 but different in the details. In order to avoid unnecessary dose to workers, the additional inspections were done on a selected subset of the reactor internals components chosen as leading indicators of potential seismic damage. The basis for their selection was listed in the prior submittal and it was noted that no damage was detected.

Therefore, in a manner consistent with the approach of MRP-227 and EPRI NP-6695, it can be concluded that there is no significant damage caused by the seismic event in the components that were not examined in detail by the inspections.

Thus the component items listed in the question, although listed for inspection by MRP-227, did not require inspection because other similar or leading indicators of damage were inspected and no damage was found. For the MRP-227 components listed in the question, the following remarks illustrate examples of this approach." Upper core barrel flange weld: This MRP-227 item was not selected because other more seismically sensitive items were inspected with no signs of damage, for example, the control rod guide tubes and their welds and bolting.* Baffle-edge bolts: This MRP-227 item is similar to the baffle former bolts that were inspected.

Also, inspection of baffle plate-to-plate gaps were another indicator that would provide evidence of seismic overload had it occurred." Baffle former assembly:

This MRP-227 item is a general condition item intended mainly to detect the initial indications of potential void swelling in the long term.Although not selected as a specific examination item for North Anna the overview inspections of the baffle assembly together with the specific baffle bolt inspections and edge gap inspections provided abundant evidence of the lack of damaging effect on the overall integrity of the baffle assembly." Thermal shield flexures:

These were included in MRP-227 inspection requirements due to the potential for fatigue cracking failure due to flow induced vibration of the thermal shield. The absence of such failures was confirmed in 2010 for North Anna Unit 2 and 2009 for North Anna Unit 1 during their respective 10 year ISI B-N-3 inspections of the external core barrel items. The examination was performed to MRP-227 criteria and no indications were identified.

The flexures do not provide a critical core support function.

Therefore, with no indications of prior fatigue damage, seismic damage to the flexures is highly unlikely and would not warrant the worker dose exposure entailed in removing the core barrel to reexamine them.* Hold-down spring: This item is supported 360 degrees around its circumference by the compressive loading from the upper internals support plate. Therefore, it is not seismically sensitive.

The upper core support plate keyways provided equivalent evidence of a lack of interface overload between the major assemblies of the reactor internals.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 15 of 17 In summary, the above items required by MRP-227 were not inspected because of the differences between an aging management inspection and a seismic damage inspection, and the inspections that were performed adequately assess the condition of the internals as a whole.In Dominion's October 10, 2011 letter (Serial No. 11-566A), it was noted that the current level of IASCC cracking in the baffle bolts would be very low based on the installed Type 316 cold worked (CW) material being less susceptible to IASCC than Type 347 bolting, which has been shown by recent ultrasonic (UT) testing to have a low rate of cracking due to IASCC. It is not possible to develop a precise estimate of the number of bolts affected by IASCC at the North Anna reactors, but a reasonably conservative estimate can be made based upon engineering judgment.

Reactor internals operating experience has been summarized in a revised version of MRP-227, MRP-227-A, that has been submitted to the staff by EPRI for final approval.

Using the US domestic operating experience as being most relevant, the plants that have had baffle former bolts inspected include Point Beach in 1998, the two Farley units in 1998 and 1999, Ginna in 1999 and 2011, Crystal River (a B&W reactor design) in 2005, and the two Surry reactors in 2010 and 2011. The Farley inspections are most relevant to North Anna because it is a three loop reactor design with Type 316CW bolting. The Point Beach Unit 2 and Ginna reactors are two loop designs with Type 347 bolting. The testing of these latter two reactors indicated a relatively high rate of UT indications (7% -9%) using the available UT technology in 1998-1999, but mechanical testing of a sample of Point Beach bolting revealed a flaw rate of approximately 3%. The 2011 UT testing by Ginna of approximately 100 of its original Type 347 bolts resulted in one indication for a 1 % flaw rate. The most relevant experience for Type 347 baffle former bolting for North Anna is considered to be the two Surry reactor inspections because its reactors are a very similar Westinghouse design, have been operated by the same utility since construction, and have accumulated significantly greater operating hours than the Point Beach and Ginna units had at the time of their inspections in 1998 and 1999. The UT inspections of the Surry reactors revealed only a total off three flaws out of the 2176 baffle former bolts inspected, for a rate of 0.1%. The Crystal River inspection of its baffle former bolts identified zero flaws in its Type 304 bolting for a 0% rate. The Farley data is also considered most relevant because it had the same Type 316CW bolting as North Anna. The Farley units inspected 2174 bolts by UT and detected zero flaws, for a rate of 0%. Based on these most recent and reliable data, the 0.1% rate experienced at Surry is considered bounding as a best estimate of the current flaw prevalence rate at North Anna. To add further conservatism to the evaluation and allow for possibly undetected flaws in the referenced data, the flaw prevalence rate at North Anna is considered bounded with high confidence by a 0.5% rate. Equivalently, 99.5% of the baffle former bolts are considered fully capable of performing their function.The criterion for acceptance of flawed baffle bolts is developed by assuming a series of patterns of failed bolts and verifying that the remaining bolts can withstand normal and design basis loading, including seismic and LOCA loads. The acceptability of the Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 16 of 17 patterns thereby assures the structural integrity of the baffle former assembly and its ability to perform its safety functions despite the assumed flaws. The details of the methodology for performing this analysis is described in the NRC staff approved topical report WCAP-1 5029-P-A, "Westinghouse Methodology for Validating the Acceptability of Baffke-Former-Barrel Bolting Distributions Under Faulted Load Conditions," Revision 1, dated December 1998. Implementation of this pattern analysis methodology on various Westinghouse plant designs was performed for the Westinghouse Owners Group. The analysis specific to the North Anna design is the proprietary report WCAP-15042,"Determination of Acceptable Baffle-Barrel-Bolting for Three-Loop Westinghouse 17x17 Downflow and Converted Upflow Domestic Plants" dated November 2001. The analysis found that approximately 55% to 70% of the baffle former bolts are needed for the downflow reactor designs to satisfy criteria.

In other words, 30% to 45% of the baffle former bolts could be failed and yet the remaining bolts could ensure the fulfillment of required safety functions.

The converted upflow design, of which North Anna Unit 1 is an example, can withstand a higher rate of bolting failures.

In practice, for an uninspected set of bolting for which the actual pattern is not known, only half of the analyzed rate of failed bolts is considered allowable, so the lower bound on the acceptable rate of assumed failed bolts for North Anna is considered to be half of 30%, or 15%. Thus in response to the staff request, it can be stated that a high confidence upper bound estimate of the flaw prevalence rate for the North Anna reactors is 0.5% as compared to an allowable flaw prevalence rate of 15.0%. The estimated rate is bounded by the allowable by a factor of 30:1. This constitutes a very large margin for ensuring the performance of safety function during normal and design basis loadings.Visual inspection techniques are considered adequate.

Given the very high margin of safety described, the additional worker dose required to perform UT examinations to verify a low flaw prevalence rate is not warranted.

Further, the seismic loading on the baffle plates as analyzed in the WCAP-15042 report referenced above is described as"several orders of magnitude" lower than analyzed LOCA loads that govern the stated margin. The bounding DBE amplified response spectra used in that analysis was anchored to 0.3g zero period acceleration and for frequencies between four and sixteen Hz did not fall below 1.2g. Therefore, there is reasonable expectation of no damage to the North Anna baffle former bolting due to the seismic event. Finally, utilization of visual inspection techniques for detection of significant damage to bolting has been shown to be effective by operating experience.

For example, a grouping of failed Type 347 baffle former bolts at a mid-west domestic reactor was detected and its extent was mapped by visual inspections.

Also, failure of radial support clevis insert retention bolting was identified by visual inspections at another reactor. Referring to Dominion's October 10, 2011 letter which discussed this subject, the adverse conditions listed as inspection attributes for baffle former bolting include the bolting damage effects seen at these reactors.

Therefore, the visual inspection techniques used for detection of damage to the baffle former bolting is considered to be adequate for its intended purpose.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Page 17 of 17 Requested Clarifications

-CVIB Question 4 In an October 7, 2011 phone call, the NRC staff requested a quantitative assessment to confirm the margins in the leak-before-break (LBB) analysis after considering the August 23, 2011 earthquake.

As a minimum address the 5 critical locations to establish adequate margins for crack growth and leakage.Dominion Response As described in Attachment 2 of Dominion's letter dated October 18, 2011 (Serial No. 11-577A), a quantitative comparison of two parameters, Cumulative Absolute Velocity (CAV) and Base Shear Loading on the containment basemat, established that the influence of the August 23, 2011 earthquake was less severe than the Design Basis Earthquake (DBE). Dominion's previous response on the LBB question concluded that the LBB analysis was still valid based upon the existing margin in the analysis without quantifying the load due to the recent earthquake and revising the fracture mechanics evaluation.

In order to quantitatively support our previous conclusions, based upon margin, a representative reactor coolant loop was analyzed for the recorded response spectra in the containment building, corrected to the appropriate building elevation.

The seismic load from this analysis was compared with the design basis seismic loading. The load on the loop piping due to the recent earthquake is found to be less than the seismic loading due to DBE. The other loads remaining the same, the existing LBB analysis remains valid.

Serial Number 11-566B Docket Nos. 50-338/339 Response to Request for Information

-Restart Readiness Determination Plan Attachment Undervoltage/Degraded Voltage Relay Test Data Virginia Electric and Power Company (Dominion)

North Anna Power Station Units 1 and 2 Serial Number 11-566B Docket Nos. 50-338/339 Page 1 of 6 NON-TECH SPEC: 74% Loss of Voltage (EDG Start Only)Phase A & B Phase B & C Phase A & C Channel 1 & 2 Channel 1 & 2 Channel 1 & 2 3/28/2009 1H 62A-1ENSH03 2.3 1.36 1.37 1.36 10/6/2010 1H 62A-1ENSH03

-< 2.3 0.69 0.81 0.88 10/10/2011 1H 62A-1ENSH03

-52.3 1.35 1.39 1.42 TRM Table 4.5-1 #13.a: 5 13.3 0.2 seconds AND TS SR 3.3.5.2.a:

2 +/-1 seconds IH Bus Timers 74% Loss OT Voltage D Phase A & B Phase B & C Phase A & C Timer IChannel 1 & 2 Channel 1 & 2 Channel 1 & 2 Relay 3/28/2009 1H 62B-1ENSH03

-< 3.1 2.19 2.19 2.19 3/18/2009 1 to 3 1.99 10/6/2010 1H 62B-1ENSH03

- 3.1 2.22 2.27 2.29 9/20/2010 1 to 3 2.04 10/10/2011 1H 62B-1ENSH03

-3.1 2.25 2.25 2.25 not tested* 1 to 3 TRM Table 4.5-1 #13.b: < 74.0 -10 seconds AND TS SR 3.3.5.2.b.2:

56 +/-7 seconds 90% Degraded Volta ge Date Bus Circuit AC Phase A & B Phase B & C Phase A & C AC Timer Relay 3/28/2009 1H 62-1ENSH03

-< 64 56.8 55.5 55.4 49 to 63 56.5 10/6/2010 1H 62-1ENSH03

< 64 52.8 53.0 58.0 49 to 63 52.6 10/10/2011 IH 62-1ENSH03 1 64 52.0 55.0 57.6 49 to 63 56.8 TRM Table 4.5-1 #13.b: 5 11.5 0.2 seconds AND TS SR 3.3.5.2.b.1:

7.5 +/-1.5 seconds 90% Degraded Voltage with SI Timer Relay Date Bus Circuit AC Channel 1 & 2 AC Channel3 4 I Channel 3 & 4 3/28/2009 IH 62S-1ENSH03 59.3 8.08 6.0 to 9.0 7.88 10/6/2010 IH 62S-1ENSH03

-< 9.3 8.00 6.0 to 9.0 7.92 10/10/2011 1H 62S-1ENSH03

-< 9.3 8.20 6.0 to 9.0 7.80* Typically performed with the Unit defueled Serial Number 11-566B Docket Nos. 50-338/339 Page 2 of 6 NON-TECH SPEC: 74% Loss of Voltage (EDG Start Only)Phase A & B Phase B & C Phase A & C D B Channel 1 & 2 Channel 1 & 2 Channel 1 & 2 3/28/2009 1J 62A-1ENS J03 <2.3 1.27 1.26 1.25 10/5/2010 1J 62A-1ENSJ03

-52.3 1.28 1.26 1.32 9/26/2011 1 J 62A-1 ENSJ03 -< 2.3 1.49 1.46 1.49 1J Bus Timers TRM Table 4.5-1 #13.a: < 13.3 0.2 seconds AND TS SR 3.3.5.2.a:

2 +/-1 seconds 74% Loss of Voltace Phase A & B Phase B & C Phase A & C Timer Date Bus Circuit AC Channel Channel 1 & 2 Channel 1 & 2 Date AC Relay 1 & 2 Relay 3/28/2009 1J 62B-1ENSJ03

- 3.1 2.06 2.07 2.05 3/20/2009 1 to 3 1.93 10/5/2010 IJ 62B-1ENSJ03

< 3.1 2.05 2.07 2.10 9/22/2010 1 to 3 2.02 9/26/2011 IJ 62B-1 ENSJ03 < 3.1 2.30 2.24 2.30 not tested* 1 to 3 TRM Table 4.5-1 #13.b: 5 74.0 -10 seconds AND TS SR 3.3.5.2.b.2:

56 +/-7 seconds 90% Degraded Voltage Phase A & B Timer Phase Phase B & C Phase A & C Relay D B C Channel 1 & 2 Channel 1 & 2 Channel 3 1 &24 3/28/2009 1J 62-1 ENSJ03 - 64 56.0 57.0 59.0 49 to 63 56.0 10/5/2010 1J 62-1ENSJ03

- 64 53.4 56.6 58.8 49 to 63 53.4 9/26/2011 1J 62-1ENSJ03

< 64 55.0 56.6 56.6 49 to 63 54.4 TRM Table 4.5-1 #13.b: 5 11.5 0.2 seconds AND TS SR 3.3.5.2.b.1:

7.5 +/-1.5 seconds 90% Degraded Voltage with SI Date Bus Circuit AC Channel AC Timer Relay 1 1 & 2 Channel 3 & 4 3/28/2009 IJ 62S-1ENSJ03 9.3 7.88 6.0 to 9.0 7.8 10/5/2010 IJ 62S-1ENSJ03

< 9.3 7.80 6.0 to 9.0 7.8 9/26/2011 1J 62S-1ENSJ03

-< 9.3 8.13 6.0 to 9.0 7.8* Typically performed with the Unit defueled Serial Number 11-566B Docket Nos. 50-338/339 Page 3 of 6 NON-TECH SPEC: 74% Loss of Voltage (EDG Start Only)Phase A & B Phase B & C Phase A & C Channel 1 & 2 Channel 1 & 2 Channel 1 & 2 10/8/2008 2H 62A-2ENSH03

-5 2.3 1.45 1.42 1.43 4/19/2010 2H 62A-2ENSH03 5 2.3 1.44 1.42 1.44 10/14/2011 1 2H 62A-2ENSH03 52.3 1.4 1.4 1.4 2H Bus Timers TRM Table 4.5-1 #13.a: 5 13.3 0.2 seconds AND TS SR 3.3.5.2.a:

2 +/-1 seconds 74% Loss of Volta e Phase A & B Phase B & C Phase A & C Timer D Channel 1 & 2 Channel 1 & 2 Channel 1 & 2 Relay 10/8/2008 2H 62B-2ENSH03 5 3.1 2.27 2.27 2.30 9/25/2008 1 to 3 2.15 4/19/2010 2H 62B-2ENSH03

-5 3.1 2.23 2.28 2.27 4/8/2010 1 to 3 2.06 10/14/2011 2H 62B-2ENSH03 53.1 2.16 2.17 2.185 10/2/2011 1 to 3 1.91 TRM Table 4.5-1 #13.b: < 74.0 -10 seconds AND TS SR 3.3.5.2.b.2:

56 +/-7 seconds 90% Degraded Voltage Timer Date Bus Circuit AC Phase A & B Phase B & C Phase A & C AC Relay Channel 1 & 2 Channel 1 & 2 Channel 1 & 2 Channel 3&4 10/8/2008 2H 62-2ENSH03 5 64 55.4 56.8 58.2 49 to 63 55.4 4/19/2010 2H 62-2ENSH03 5 64 56.0 57.6 59.0 49 to 63 55.6 10/14/2011 2H 62-2ENSH03

-5 64 56.1 56.7 56.8 49 to 63 55.9 TRM Table 4.5-1 #13.b: _ 11.5 0.2 seconds AND TS SR 3.3.5.2.b.1:

7.5 +/-1.5 seconds 90% Degraded Voltage with SI Date Bus Circuit AC Channel 1 & AC Timer Relay 1_2 Channel 3 & 4 10/8/2008 2H 62S-2ENSH03

<5 9.3 8.14 6.0 to 9.0 8.00 4/19/2010 2H 62S-2ENSH03

< 9.3 7.88 6.0 to 9.0 7.96 10/14/2011 2H 62S-2ENSH03

-< 9.3 8.20 6.0 to 9.0 7.95 Serial Number 11-566B Docket Nos. 50-338/339 Page 4 of 6 NON-TECH SPEC: 74% Loss of Voltag (EDG Start Only)Phase A & B Phase B & C Phase A & C Date Bus Circuit AC Channel 1 & 2 Channel 1 & 2 Channel 1 & 2 10/7/2008 2J 62A-2ENSJ03

-< 2.3 1.40 1.40 1.45 4/19/2010 2J 62A-2ENSJO3

-5 2.3 1.38 1.41 1.40 10/17/2011 2J 62A-2ENSJ03

-< 2.3 1.25 1.23 1.24 2J Bus Timers TRM Table 4.5-1 #13.a: < 13.3 0.2 seconds AND TS SR 3.3.5.2.a:

2 +/-1 seconds 74% Loss of Voltage Date Bus Circuit AC Phase A & B Phase B & C Phase A & C Date AC Timer Channel 1 & 2 Channel 1 & 2 Channel 1 & 2 Relay 1017/2008 2J 62B-2ENSJ03 5 3.1 2.25 2.40 2.25 9/29/2008 1 to 3 2.03 4/19/2010 2J 62B-2ENSJO3

-5 3.1 2.25 2.25 2.25 4/7/2010 1 to 3 1.98 10/17/2011 2J 62B-2ENSJO3 1 3.1 2.12 2.12 2.10 9/24/2011 1 to 3 2.03 TRM Table 4.5-1 #13.b: 5 74.0 -10 seconds AND TS SR 3.3.5.2.b.2:

56 +/-7 seconds 90% Degraded Voltage Date Bus Circuit AC Phase A & B Phase B & C Phase A & C AC Timer Relay Channel 1 & 2 Channel 1 & 2 Channel 1 & 2 Channel 3 & 4 10/7/2008 2J 62-2ENSJO3

-< 64 57.0 57.5 57.6 49 to 63 57.0 4/19/2010 2J 62-2ENSJO3

-5 64 56.8 56.8 57.0 49 to 63 56.4 10/17/2011 2J 62-2ENSJO3 64 56.6 56.8 56.9 49 to 63 56.4 TRM Table 4.5-1 #13.b: _ 11.5 0.2 seconds AND TS SR 3.3.5.2.b.1:7.5

+/-1.5 seconds 90% Degraded Voltage with SI Date Bus Circuit AC Channel 1 & 2 AC Timer Relay Channel 3 & 4 10/7/2008 2J 62S-2ENSJO3

-5 9.3 8.40 6.0 to 9.0 7.90 4/19/2010 2J 62S-2ENSJO3

-5 9.3 8.28 6.0 to 9.0 8.04 10/17/2011 2J I62S-2ENSJO3 1 9.3 8.02 6.0 to 9.0 8.00 Serial Number 11-566B Docket Nos. 50-338/339 Page 5 of 6 TS SR 3.3.5.2.a:

2935 to 3225 volts Loss of Voltag Drop Out (DO) Voltage Relay Relay Relay Date Bus AC 27A-2H3 27B-2H3 27C-2H3 9/25/2008 2H 48.41 to 53.20 49.6 50.2 48.8 4/8/2010 2H 48.41 to 53.20 52.0 50.2 52.4 10/4/2011 2H 48.41 to 53.20 49.7 50.5 49.2 TS SR 3.3.5.2.b:

3720 to 3772 volts

Dearaded Voltaae DroD Out (DO) Voltage 2H Bus UVIDV I I Relays Relay Relay Relay Relay Relay Relay 27AJB/C-2H1,

Phase 27A/B/C-2H1, Phase 27A/B/C-2H1, Phase 27A/B/C-2H1-A, 27A/B/C-2H1-A, 27A/B/C-2H1-A, Date Bus AC A B C Phase A Phase 6 Phase C 9/25/2008 2H 61.36 to 62.22 B1.84 61.77 61.73 6 A.74 61.75 6B.75 4/8/2010 2H 61.36 to 62.22 61.82 61.869 61.870 61.759 61.841 61.900 10/4/2011 2H 61.36 to 62.22 61.95 61.99 61.98 61.68 61.89 61.99 Non-Tech Spec OverlUnderlDec raded Voltage Pickup (PU) Volt ge Relay Relay Relay Relay Relay Relay 27A/B/C-2H 1 27A/B/C-2H1 27A/B/C-2H 1 27A/B/C-2H 1-A 27A/B/C-2H 1-A 27A/B/C-2H 1-A Date Bus AC AB BC CA AB BC CA 9/25/2008 2H D 1.01 x DO 62.43 62.39 62.32 62.33 62.33 62.34 4/8/2010 2H -5 1.01 x DO 62.468 62.450 62.469 62.308 62.423 62.469 10/4/2011 2H -5 1.01 x DO 62.52 62.61 62.60 62.30 62.50 62.61 Non-Tech Spec OverlUnderlDec raded Voltage Dropout (DO) Vol age Relay Relay Relay Relay Relay Relay 27A/B/C-2H 1 27A1B/C-2H1 27A/B/C-2H1 27A/B/C-2H1-A 27A/B/C-2H1-A 27A/B/C-2H1-A Date Bus AC AB 6C CA AB BC CA 9/25/2008 2H 61.36 to 62.22 61.84 61.77 61.73 61.74 61.75 61.75 4/8/2010 2H 61.36 to 62.22 61.882 61.869 61.870 61.759 61.841 61.900 10/4/2011 2H 61.36 to 62.22 61.95 61.99 61.98 61.68 61.89 61.99 Non-Tech Spec OverlUnder/De¢ raded Voltage Pickup (PU) Volt ge Relay Relay Relay Relay Relay Relay 27A-2H2 27B-2H2 27C-2H2 27A-2H3 27B-2H3 27C-2H3 Date Bus AC Phase A Phase B Phase C Phase A Phase B Phase C 9/25/2008 2H 5 1.01 x DO 52.90 52.50 51.90 53.30 51.90 54.80 4/8/2010 2H < 1.01 x DO 55.9 55.1 54.4 56.30 53.90 55.20 10/4/2011 2H < 1.01 x DO 53.3 52.9 53.9 53.0 1 53.1 53.8 Non-Tech Spec Over/UnderlDec raded Voltage Dropout (DO) Vol age Relay Relay Relay Relay Relay Relay 27A-2H2 27B-2H2 27C-2H2 27A-2H3 27B-2H3 27C-2H3 Date Bus AC Phase A Phase B Phase C Phase A Phase B Phase C 9/25/2008 2H 48.41 to 53.20 50.10 49.20 49.60 49.60 50.20 48.80 4/8/2010 2H 48.41 to 53.20 51.20 52.20 51.70 52.0 50.2 52.4 10/4/2011 2H 48.41 to 53.20 50.3 49.9 49.9 49.7 50.5 49.2 Serial Number 11-566B Docket Nos. 50-338/339 Page 6 of 6 TS SR 3.3.5.2.a:

2935 to 3225 volts Loss of Voltage Drop Out (DO) Voltage Relay Relay Relay Date Bus AC 27A-2J3 27B-2J3 27C-2J3 9/29/2008 2J 48.41 to 53.20 49.30 50.10 50.20 47/12010 2J 48.41 to 53.20 51.50 51.30 51.10 9/24/2011 2J 48.41 to 53.20 48.80 50.00 49.10 I JBu VI Relays I TS SR 3.3.5.2.b:

3720 to 3772 volts Degraded Voltage Dro Out (DO) Voltage Date Bus AC 9/29/2008 2J 61.36 to 62.22 4/7/2010 2J 61.36 to 62.22 9/24/2011 2J 61.36 to 62.22 Relay 27A/B/C-2J 1, Phase A 61.82 61.836 not tested*iii Relay 27A/B/C-2J1, Phase B 61.83 61.848 not tested*Relay 27ANB/C-2J1, Phase C 61.74 61.874 not tested*Relay 27A/B/C-2J 1 -A Phase A 61.65 61.84" 61.89 Relay 27A/B/C-2J1-A, Phase B 61.75 61.838 61.89 Relay 27A/B/C-2J1-A, Phase C 61.83 61.847 61.90 Non-Tech Spec Over/Under/Dec aded Voltage Pickup (PU Voltage Relay Relay Relay Relay Relay Relay Date Bus AC 27N/B/C-2J11, AB 27N/B/C-2J11 BC 27ANB/C-2J1, CA 27A/B/C-2J 1-A, AB 27A/B/C-2J1-A, BC 27NIB/C-2J1-A, CA 9/29/2008 2J -< 1.01 x DO 62.43 62.43 62.35 62.24 62.31 62.40 4/7/2010 2J -5 1.01 x DO 62.432 62.446 62.474 62.414 62.415 62.429 9/24/2011 2J -< 1 01 x DO not tested* not tested* not tested* 62.46 62.48 62.42 Non-Tech Spec Over/Under/Dec raded Voltage Dropout (D) Voltage Relay Relay Relay Relay Relay Relay Date Bus AC 27N/B/C-2J1, AB 27N/B/C-2J1I, BC 27N/B/C-2J1, CA 27A/B/C-2J11-A, AB 27A/B/C-2J1-A, BC 27A/B/C-2J1 -A, CA 9/29/2008 2J 61.36 to 62.22 61.82 61.83 61.74 61.65 61.75 61.83 417/2010 2J 61.36 to 62.22 61.836 61.846 61.874 61.846 62.838 611.847 9/24/2011 2J 61.36 to 62.22 not tested* not tested* not tested* 61.89 61.89 61.90 Non-Tech Spec Over/Under/De raded Voltage Pickup (PU Voltage Relay Relay Relay Relay Relay Relay Date Bus AC 27A-2J2, Phase A 27B-2J2, Phase B 27C-2J2, Phase C 27A-2J3, Phase A 27B-2J3, Phase B 27C-2J3, Phase C 9/29/2008 2J <5 1.01 x DO 53.30 51.00 51.60 52.60 63.50 53.20 411/2010 2J 5 1.01 x DO 54.30 53.60 53.40 54.40 54.20 53.90 9/24/2011 2J <5 1.01 x DO 53.60 52.00 51.60 53.10 53.20 54.20 Non-Tech Spec Over/Under/Dec raded Voltage Dropout (D) Voltage Relay Relay Relay Relay Relay Relay 9/29/2008 2J 48.41 to 53.20 50.60 50.10 50.00 49.30 50.10 50.20 41/12010 2J 48.41 to 53.20 51.90 50.90 51.30 51.50 51.30 51.10 9/24/2011 2J 48.41 to 53.20 50.30 49.70 50.10 48.80 50.00 49.10-The 2J1 UV relay as found voltages were not obtained due to a power supply failure. The Control Power lights to the UV relay were verified to be operating following the seismic event.The relay power supply failure appears to be due to cycling power to it for the testing and not seismically induced. The relay was replaced.