ML11277A267

Response to Request for Additional Information Regarding August 23, 2011 Earthquake - Restart Readiness Determination Plan

ML11277A267
Person / Time
Site:	North Anna
Issue date:	10/03/2011
From:	Grecheck E Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
11-566
Download: ML11277A267 (42)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 October 3, 2011 10 CFR 100, Appendix A U.S. Nuclear Regulatory Commission Serial No.: 11-566 Attention: Document Control Desk NL&OS/ETS R2 Washington, DC 20555 Docket Nos.: 50-338 50-339 License Nos.: NPF-4 NPF-7 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

NORTH ANNA POWER STATION UNITS 1 AND 2 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING THE AUGUST 23, 2011 EARTHQUAKE - RESTART READINESS DETERMINATION PLAN By letters dated September 17 and 27, 2011, (Serial Nos.11-520 and 520A, respectively), Dominion provided information regarding North Anna Power Station's response to the August 23, 2011 Central Virginia earthquake, as well as a Restart Readiness Determination Plan. By letters dated September 26, 28 and 30, 2011, the NRC requested additional information regarding the Restart Readiness Determination Plan to facilitate review of Dominion's restart activities. Therefore, Dominion is providing, in part, responses to the questions identified by the various NRC technical review branches. The specific technical review areas and the associated questions being answered in the attachment to this letter are provided below for reference:

HVAC Related Structures Questions 1 and 2 Containment Questions 1 through 5 Electrical Questions 1, 2, 3, 6 and 7 Instrumentation and Controls Questions 1 through 3 Fire Protection Questions 1 through 4 Probabilistic Risk Assessment Question 1 Steam Generators Questions 1 and 3 Snubbers Questions 1 through 4 Reactor Vessel Internals Questions 1 and 4 Responses to the remaining questions received will be provided in a subsequent letter(s) once their associated activities have been completed and results documented.

Serial Number 11-566 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

Attachment:

Response to Request for Additional Information - August 23, 2011 Earthquake Restart Readiness Determination Plan 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 in 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 day of 0*)L4" ,2011.

My Commission Expires: 4.*-4 201 .

Ginger Lynn Rutherford NOTARY PUBLICI Commonwealth of Virginia (Notary Public Reg. # 310847 My Commission Expires 4/30/2015

Serial Number 11-566 Docket Nos. 50-338/339 Page 3 of 3 cc: Regional Administrator 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 11-566 Docket Nos. 50-338/339 Attachment Response to Request for Additional Information August 23, 2011 Earthquake - Restart Readiness Determination Plan Virginia Electric and Power Company (Dominion)

North Anna Power Station Units 1 and 2

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page.1 of 38 Response to NRC Requests for Additional Information North Anna Power Station Units I and 2

Background

By letters dated September 17 and 27, 2011, (Serial Nos.11-520 and 520A, respectively), Dominion provided information regarding North Anna Power Station's response to the August 23, 2011 Central Virginia earthquake, as well as a Restart Readiness Determination Plan. By letters dated September 26, 28 and 30, 2011, the NRC requested additional information to facilitate review of Dominion's restart activities.

Therefore, Dominion is providing, in part, responses to the questions (typed in italics) identified by the various NRC technical review branches. The responses are provided below. Responses to the remaining questions will be provided once the associated activities have been completed and documented.

NRC Request for Information Heating, Ventilating and Air Conditioning

1. Provide the basis for concluding that the bypass leakage of the safety-related charcoalfilters meets technical specifications.

Dominion Response A comprehensive external inspection of the safety related Emergency Core Cooling System (ECCS) Pump Room Exhaust Air Cleanup System (PREACS) ventilation duct work, dampers and filters was performed after the seismic event. There were no indications of any seismic related damage on the duct work, supports or components. By-pass leakage for the charcoal filters would only be affected if the by-pass dampers were physically altered to create a by-pass flow path internal to the damper. An ECCS PREACS flow test was performed on August 27, 2011 with no issues identified when stroking the dampers. The ECCS PREACS Train A filter (1-HV-FL-3A) in-place test is scheduled to be performed prior to either unit entering Mode 4 to confirm that bypass leakage is less than the Technical Specifications 1% acceptance criteria.

The ECCS PREACS charcoal filter banks (1-HV-FL-3A and 1-HV-FL-3B) are located on the 291 foot elevation of the Auxiliary Building and are seismically qualified. For components with natural frequencies less than 10 Hz, accelerations of 5.5g horizontal and 4.1g vertical were used for equipment qualification. For other components with a natural frequency greater than 10 Hz, an acceleration value of 0.35g was used. The qualification levels documented in the vendor's analysis envelop the seismic demand corresponding to the installed location of the equipment.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 2 of 38

2. Please provide the basis for concluding that the control room in-leakage remains less than assumed in the control room habitabilitydose analysis.

Dominion Response A comprehensive inspection of the building structures was performed after the seismic event. This included the walls, floors and ceilings that form the Control Room Envelope (CRE) pressure boundary. There were no indications of any structural damage that would affect the integrity of the CRE pressure boundary. On September 1, 2011, a sampling of fifty-five (55) fire barrier penetrations was inspected throughout the Unit 2 Emergency Switchgear Room. The inspected penetrations were determined to be in good condition with no signs of degradation. The passive fire barriers inspected continue to meet their functional requirements. A comprehensive inspection of the duct work, supports and components that support the CRE pressure boundary was also performed with no indication of any deficiencies identified that would affect the CRE pressure boundary. In addition, measurement of the CRE pressure relative to the external areas adjacent to the CRE pressure boundary will be completed with the CRE operating in the outside supply mode of operation prior to entering Mode 4.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 3 of 38 Containment

1. Explain how VEPCO has re-establishedOPERABILITY of the containment?

Dominion Response Inspections were completed on the containment structures and associated systems consistent with the guidance of EPRI Technical Report No. NP-6695, Guidelines for Nuclear Plant Response to an Earthquake. The inspections included the structures, systems and components (SSCs) inside containment as well as the containment structure itself. No significant physical or structural damage was identified to any safety related SSCs during the detailed inspections. Only minor damage of an interior wall was identified (i.e., some cracking of grout at the junction of two original construction concrete pours).

As described in the response to questions 2 and 3 below, the engineering evaluations determined that the load demand reached in the North Anna Power Station containment structures, as a result of the August 23, 2011 earthquake, would not have adversely challenged the design capacity of these containment structures.

Based on the fact that SSCs inspections have not identified any significant physical or functional damage, the containment structure building system, and the associated mechanical and electrical systems housed within, are determined to be Operable.

2. Explain whether VEPCO has performed analyses of the stresses specifically of containment structures?

3. What were the results? If analyses were not performed, discuss why such analyses are not needed priorto restart.

Dominion Response (2 and 3)

In lieu of performing specific stress analyses of the containment structures, Dominion cites the following four (4) evaluations to justify that load demand did not adversely challenge the structural integrity or exceed the available design capacity of North Anna Power Station containment structures as a result of the August 23, 2011 Central Virginia Earthquake,

1. The exterior shell and interior reinforced concrete surfaces of the containment structures were inspected in accordance with the acceptance criteria, as listed in EPRI Technical Report No. NP-6695, (Table 5-1), to determine whether any significant damage existed that would be consistent with yielding of reinforcing steel.

The metal containment liner was visually inspected for cracks, buckled areas or pitted surfaces. Steel structures in containment were also inspected in accordance with the acceptance criteria listed in EPRI Technical Report No. NP-6695, (Table 5-

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 4 of 38

1) to determine whether there was any significant damage at bolted and welded connections, anchorages, as well as any movement or distortion of members. Based on the results of these "Expanded Inspections," there was no visual evidence of any significant physical or functional damage to any safety related SSCs associated with the North Anna Power Station containment structures (Reference Dominion Letter dated September 17, 2011.)

Although visual inspections have been performed, the possibility of "hidden damage",

(i.e., damage to the SSCs that cannot be identified visually), was also considered.

Based on the lack of significant physical or functional damage to safety related plant SSCs, and only limited damage to non-safety related, non-seismically designed SSCs, as documented in the System and Structural Component inspections, no hidden damage is expected. This is based on the review of industry insights from EPRI research related to the performance of the Kashiwazaki-Kariwa Nuclear Power Station. Similarly, with respect to North Anna Power Station containment structures, based on the observed lack of significant physical or functional damage on the surface, it is concluded that there is no hidden damage within the North Anna containment structures.

2. Dominion's Response Letter dated September 17, 2011, included as Table 3 in Enclosure 1, a summary of the Cumulative Absolute Velocity (CAV) index values calculated by three different organizations following the August 23, 2011 earthquake at North Anna Power Station, including preliminary results from Bechtel. The following is a corrected version of the Table, which includes the finalized calculations by Bechtel.

Cumulative Absolute Velocity Results East-West (g-sec) North-South (g-sec) Vertical (g-sec)

Kinemetrics 0.137 0.175 0.118 SGH 0.118 0.169 0.105 Bechtel 0.121 0.173 0.106 Average 0.125 0.172 0.110 The highest calculated CAV index value of 0.172 (N-S), is slightly greater than the CAV limit (i.e., 0.16 g-sec ) allowed in US NRC Regulatory Guide 1.166 for an Operating Basis Earthquake (OBE).

To understand the conservatism in this established CAV limit, the following explanation is provided, (Reference EPRI TR-100082, December 1991):

"The adjusted CAV threshold is about a factor of five lower than the lowest CAV value associated with documented damage to an industrial/power facility. It is about a factor of three lower than the lowest CAV value

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 5 of 38 associated with documented damage to buildings of good design and construction."

Although the containment basemat generated response spectral values exceeded the design basis earthquake (DBE) accelerations over a range of frequencies, response spectral exceedance is a poor indicator of expected damage. The CAV index is recognized as the best single parameter to use to assess the potential for earthquake damage, since the CAV index includes the effects of ground motion duration. The CAV limit was established to be consistent with the expected damage of a non-seismically designed structure "of good design and construction,"

(Reference EPRI TR-100082, December 1991), following an OBE (Reference US NRC Regulatory Guide 1.166, Section 4.2). The effective duration of strong motion accelerations in the North-South (N-S) direction was determined to be only one (1) second. That is why the calculated CAV index value in the N-S direction is relatively low, even though DBE spectral accelerations were exceeded in both the low and high frequency ranges for the N-S direction. Hence, these calculated CAV index values corroborate the visual results of the "Expanded Inspections," which concluded that no significant physical or functional damage was observed for any safety related SSCs.

As reported in Dominion's letter dated September 17, 2011, peak seismic accelerations recorded at the basemat of containment had limited effective strong motion accelerations over the following time durations, for the following directions as listed below:

• 3.1 seconds (E-W)

• 1.0 second (N-S)

• 1.5 seconds (Vertical).

Note that the highest calculated CAV index value of 0.172 g-sec occurred in the N-S direction, which corresponds to the shortest recorded strong motion acceleration duration of 1.0 second. Conversely, the longest effective strong motion acceleration duration of 3.1 seconds corresponds to the E-W direction, for which a CAV index value of 0.125 g-sec was calculated. Based on these relatively low calculated CAV index values and the relatively short duration of strong motion accelerations, the damaging potential of this earthquake was limited. Although the containment basemat generated response spectral values from the August 23, 2011 earthquake exceeded some DBE design limits, the earthquake did not maintain effective strong motion accelerations over a sufficient duration of time to cause significant physical or functional damage to safety related SSCs.

3. As reported in Dominion letter dated September 17, 2011, limited scope plant inspections were conducted by a Seismic Review Team that included Dominion and industry seismic experts. The scope of these inspections did not include the containment structures, since containment structures are not considered to be

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 6 of 38 earthquake damage indicators. Instead, the focus of inspections was on structures that were identified as earthquake damage indicators [i.e., non-seismic structures and seismic structures, such as block walls, known to have high confidence of low probability of failure (HCLPF) capacities less than 0.3g from the Individual Plant Examination for External Events (IPEEE) study]. Based on the results of these inspections, the industry seismic experts concluded that no significant earthquake-induced damage was observed for the areas and SSCs inspected. Containment structures are robustly designed, with sufficient capacity to resist their demand loads within the linear range and are provided with special detailing to remain ductile. As such, no significant damage, visible or hidden, would be expected for containment structures.

4. No credit was taken for the structural strength of the metal containment liner in the structural analysis of the North Anna containment shell. All load demand is satisfied by the capacity of the reinforced concrete shell. The reinforced concrete shell is designed to accommodate the required load demand and not undergo deformations that would induce liner stresses in excess of the metal liner's design stress limits.

From a review of North Anna containment liner design basis calculations, the DBE load case is not the major load contributor to the containment shell, rather pressure and temperature load cases are the major load demand drivers for the design of the containment shell.

The August 23, 2011 earthquake occurred with the North Anna metal containment liners at approximately operating design pressure and temperature, which are listed as P0 = -5 psi and To = +45 OF (i.e., T, is the differential temperature from 70 OF) and correspond to the Normal (Cyclic) load combination. The pressure and temperature load cases, associated with the design basis accident condition (i.e., Emergency) load combination, Pd = +45 psi and Td = +201 OF (i.e., Td is the differential temperature from 70 OF), are more severe. Hence, there was significant available design capacity to absorb any additional stresses due to the August 23, 2011 earthquake. As an example of this additional available design capacity, the following comparison is provided for the Emergency and Normal (Cyclic) load combinations relative to the containment metal liner near the top of the basemat. The top of the basemat was chosen for comparison, since seismic load cases would have their greatest impact on resulting stresses at this location. Note that DBE stresses were conservatively compared in both Emergency and Normal (Cyclic) load combinations:

Emergency Load Combination, D + Pd (+45 psi) + Td (+201 OF) + DBE (Maximum Principal Stress @ T/Basemat, 0"), a, = -48.3 ksi, U2 = -51.9 ksi < 3Sin = 66 ksi Normal (Cyclic) Load Combination, D + Pd (-5 psi) + Td (+45 OF) + DBE (Maximum Principal Stress @ T/Basemat, 0"), a, = -23.6 ksi, 0 2 = -14.1 ksi < 3Sm = 66 ksi Based on the above comparison, the total analyzed DBE load demand is only approximately 1/3 of the allowable stress limit; hence, adequate design capacity

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 7 of 38 exists. Similar additional available design capacity exists for the reinforced concrete containment shell, which supports the containment metal liner.

The interior reinforced concrete containment structures function primarily as bioshield walls and pressurized compartments; hence, they are designed as relatively thick shear walls and slab sections to provide adequate radiation shielding and to resist accident pressure and temperature load cases. DBE seismic load cases are similarly included in the respective accident and normal load combinations for interior containment structures; however, the DBE load demand is only a minor portion of the total load demand on these structures. As a result, DBE loads account for a relatively minor amount of the total load demand in these interior containment structures, which are relatively thick, reinforced concrete shear walls and slab sections and can accommodate the seismic load demand. As discussed above, the August 23, 2011 earthquake occurred at normal operating pressures and temperatures; hence, there was significant available design capacity to accommodate increased load demand.

The major interior containment steel structures are a network of beams and columns, which support steel grating walkways in the annulus regions of containment. These structures are relatively lightly loaded during plant operation, since these areas mainly provide walkways for plant personnel and equipment laydown areas. These structures are braced in the lateral directions by the crane wall, so lateral seismic loads do not govern their design. The major vertical loads for these interior containment steel structures are gravity loads from plant personnel and equipment laydown loads, which were not present at the time of the event. Hence, seismic loads do not account for a major portion of the load demand on these interior containment steel structures. Similarly, there was significant available design capacity to accommodate increases in load demand at the time of the August 23, 2011 earthquake.

In summary, four (4) evaluations, described in detail above, justify that the load demand reached in the North Anna Power Station containment structures as a result of the August 23, 2011 earthquake would not have adversely challenged the design capacity of these containment structures. Specifically,

1. No significant physical or functional damage was observed on any safety related SSC's during plant inspections,

2. Relatively low CAV index values, were calculated which corroborates the plant inspection results,

3. Confirmation of the above conclusions was made by a Seismic Review Team made up of industry experts, and

4. The earthquake occurred with the plant at normal operating conditions; therefore, significant additional design capacity was available for any increased load demand in the containment structures.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 8 of 38 Based on these technical justifications, there is no need to perform additional structural analyses to ensure continued structural integrity and the availability of the required design capacity for North Anna containment structures.

4. Confirm whether VEPCO performed inservice testing on containment isolation valves during the shutdown. List the valves tested and provide the results.

Dominion Response Consistent with EPRI NP-6695, Dominion developed a methodology for performing inspections to assess significant physical or functional earthquake-related damage to SSCs. The inspections performed on the Containment Isolation Valves did not identify any significant physical or functional damage to the components that would render them incapable of performing their design functions. A more detailed discussion of the attributes of the inspections and tests performed on North Anna plant SSCs to assess the potential earthquake damage is contained in Dominion's letter dated September 17, 2011.

The following Unit 1 containment isolation valves have been satisfactorily stroke time tested to date:

1-AS-FCV- 100A 1-CH-MOV-1289A 1 -RM-TV- 100B 1-SS-TV- 100A 1-AS-FCV- 100B 1-CH-MOV- 1380 1-RM-TV-1 OC 1 -SS-TV- G00B 1-BD-TV- 100A 1-CH-MOV-1 381 1-RM-TV- 100D 1-SS-TV-101A 1-BD-TV-1 00B 1-CH-TV-1 204A 1-RS-MOV- 100A 1 -SS-TV-1 01B 1-BD-TV- 100C 1-CH-TV-1 204B 1-RS-MOV-1 GOB 1 -SS-TV-1 02A 1-BD-TV- 100D 1-CV-TV- 150A 1 -RS-MOV- 101A 1-SS-TV-102B 1-BD-TV- 100E 1-CV-TV-150B 1 -RS-MOV-1 01B 1 -SS-TV-103A 1-BD-TV- 10OF 1-CV-TV-i 50C 1 -RS-MOV- 155A 1-SS-TV-103B 1-CC-TV- 100A 1-CV-TV-i 50D 1 -RS-MOV-1 55B 1 -SS-TV-104A I -CC-TV- 100B 1-DA-TV-1 O1A 1 -RS-MOV- 156A 1-SS-TV- 104B 1-CC-TV- 100C 1-DA-TV-100B 1 -RS-MOV- 156B 1-SS-TV-1 06A 1-CC-TV-101A 1-DA-TV-103A 1-SI-HCV-1936 1-SS-TV-1 06B 1-CC-TV-101B 1-DA-TV-103B 1-SI-MOV-1836 1-SS-TV-1 12A 1-CC-TV- 102B 1-DG-TV- 100A 1-SI-MOV-1 860A 1-SS-TV-1 12B 1-CC-TV- 102C 1-DG-TV-100B 1-SI-MOV-1 860B 1-SV-TV-1 02-1 1-CC-TV- 102D 1-IA-TV- 102A 1-SI-MOV-1867C 1-SV-TV- 102-2 1-CC-TV- 102E 1-IA-TV-102B 1-SI-MOV-1867D 1-SV-TV- 103 1-CC-TV- 102F 1-MS-TV-101C 1-SI-MOV-1869A 1-SW-MOV- 103A 1-CC-TV- 103A 1-MS-TV- 113A 1-SI-MOV-1 869B 1-SW-MOV-103B 1-CC-TV-I 03B 1-MS-TV-i 13B 1-SI-MOV-1 890A 1-SW-MOV-I 03C 1-CC-TV-104A 1-MS-TV-1i13C 1-SI-MOV-1 890B 1-SW-MOV-103D 1-CC-TV- 104B 1-MS-TV- 109 1 -SI-MOV-1890C 1-SW-MOV- 104A I-CC-TV- 104C 1-MS-TV-I 10 1-SI-MOV-1 890D 1-SW-MOV-104B 1-CC-TV- 105A 1-QS-MOV-101A I-SI-TV-100 1-SW-MOV-104C 1-CC-TV-105B 1-QS-MOV-101B I-SI-TV-101 1-SW-MOV- 104D 1-CC-TV- 105C 1-RC-TV-1519A 1-SI-TV-1 842 1-VG-TV- 100A 1-CH-FCV-1160 1-RM-TV- 100A 1-SI-TV-1 859 1-VG-TV-1 00B

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 9 of 38 The following valves closed but failed their IST stroke time test and will be repaired prior to Unit 1 restart:

" 1-CC-TV-102A

• 1-MS-TV-101A

• 1-MS-TV-101B One additional valve, 1-CC-TV-104B, indicated a negative trend in stroke time (but the time was satisfactory per the surveillance procedure). It was investigated and determined that the valve stroked acceptably, but one of the two position limit switches needed adjustment. Adjustment will be completed prior to plant startup.

The list of valves scheduled for testing on Unit 2 is similar. To date, there have been no failures on Unit 2. Testing is not yet complete for Unit 2 but will be concluded prior to Unit 2 restart.

5. Confirm whether VEPCO performed a general visual inspection of the containment consistent with Title 10 of the Code of Federal Regulations, (10 CFR 50), Part 50, Appendix J and industry guidance in Nuclear Energy Institute (NEI) 94-01, "Industry Guideline for Implementing Performance-BasedOption of 10 CFR Part 50, Appendix J," and ANSI/ANS 56.8, "Containment System Leakage Testing Requirements," as referenced in RG 1.163. If performed, provide the results. If not performed, list the containment inspections performed and provide the results.

Dominion Response Consistent with the EPRI NP-6695, North Anna developed a methodology for performing inspections to assess significant physical or functional earthquake-related damage to SSCs. Using this methodology, inspections were performed on the Containment Structure. The inspections did not identify any significant physical or functional damage to the structure that would render it incapable of performing its design functions. A more detailed discussion of the attributes of the inspections and tests performed on North Anna plant SSCs to assess the potential earthquake damage is contained in Dominion's letter dated September 17, 2011.

In concert with the inspections noted in the response to Question No. 2 above, inspections were performed by civil engineering personnel on both the inside of the containment building and the exterior concrete cover. These inspections were performed on structural concrete and steel. The inspections were conducted using the EPRI NP-6695 as a guide to determine if there was any significant damage attributable to the seismic event. Condition Report (CRs) were entered into the corrective action system (CAS) questioning conditions noted during the civil engineering inspections. In addition, other station personnel generated CRs on suspect conditions that required evaluation of structural components inside containment by civil engineering. The

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 10 of 38 conclusion of both the initial inspections and other CR-prompted investigations was that no significant damage was discovered. None of the findings are considered to adversely affect the leakage integrity performance of containment.

The Appendix J general visual inspection of the containment requirements of RG 1.163, (NEI) 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," and ANSI/ANS 56.8, "Containment System Leakage Testing Requirements," are met by Technical Requirements Manual (TRM), Surveillance Requirement (TSR) 3.6.2.7. This Surveillance Requirement is fulfilled by surveillance tests 1/2-PT-61.1A which were completed following the seismic event.

Based on post-earthquake system inspections using the TSR Surveillance for guidance and documentation, no issues attributed to the earthquake were found affecting containment integrity. Type B and Type C testing has been satisfactorily performed on Unit 2 with normal results as discussed below. Appendix J tests to date have been satisfactory. Inspections, valve indications, and periodic as-found Local Leak Rate Tests (LLRT) to measure leakage of specific components indicate that containment performed as designed during the earthquake. There is no evidence of any change in the leakage characteristics of the Unit 1 and Unit 2 containment buildings as a result of the earthquake.

Post-seismic civil/structural inspections of the Unit 1 and Unit 2 Containment exteriors were completed with the use of a crane and man-basket. No areas of concern were noted. Readily accessible areas of the containment liner were thoroughly inspected for seismic defects during the post earthquake system inspections and none were identified. The potential high stress areas inside and outside of Unit 1 and 2 Containments were inspected and included the following:

• Electrical Penetration area

• Mechanical Penetration area

• Equipment Hatch

• Personnel Hatch

• Main Steam and FW Line Penetrations in Main Steam Valve House (MSVH)

• Safeguards Building Penetrations Appendix J testing will be completed prior to Unit 1 and 2 restart for the following components in accordance with Technical Specification requirements:

• Equipment Hatch

• Personnel and Escape Hatches

• Containment Purge Valves Appendix J testing of Unit 2 Electrical Penetrations has been conducted since the earthquake occurred. During each outage approximately 17% of the penetrations are tested such that all penetrations are tested every 6 refueling outages (RFOs) The results obtained are typical of Type B testing seen in previous outages, which indicates

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 11 of 38 that the electrical penetrations were not affected by the August 23, 2011 earthquake.

The following electrical penetrations have been tested on North Anna Unit 2:

0 4B and 6D, S 17A through 17E, 0 18A through 18E, 0 19A through 19E, and 0 20A through 20E.

The Type B leakage testing results were 7% of the average annual Type B leakage.

These results are typical of Type B testing performed in previous outages and are shown below:

Post Seismic, Unit 2 Containment, Type B Tests of Electrical Penetrations Test Date Penetration Measured leakage Leakage Limit (scfh) (scfh) 8/25/2011 4B 0.001 0.056 8/24/2011 6D 0.006 0.056 8/24/2011 17A 0.001 0.056 8/24/2011 17B 0.001 0.056 8/24/2011 17C 0 0.056 8/24/2011 17D 0.001 0.056 8/24/2011 17E 0.001 0.056 8/24/2011 18A 0.002 0.056 8/24/2011 18B 0.006 0.056 8/24/2011 18C 0.003 0.056 8/24/2011 18D 0.007 0.056 8/24/2011 18E 0.003 0.056 8/26/2011 19A 0.004 0.056 8/26/2011 19B 0.002 0.056 8/26/2011 19C 0.001 0.056 8/26/2011 19D 0.005 0.056 8/26/2011 19E 0.007 0.056 8/25/2011 20A 0.001 0.056 8/25/2011 20B 0 0.056 8/25/2011 20C 0 0.056 8/25/2011 20D 0 0.056 8/25/2011 20E 0.001 0.056 Totals 0.053 1.232 Average total Type B leakage 0.75 0.6 La 182.6

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 12 of 38 Actual Type B leakage is 4.3% of the allowable limit of the summation of the individual penetration limits and 0.055% of the allowable limit of 0.6 La for all Type B and C leakage.

The status of Unit 2 Type C testing to date and the specific valve data is included below.

As Found Test Data Total Number of Valves to Test 105 Number of Valves Tested 79 Percent of As-Found Complete 75.24%

Total As-Found Leakage 9.20 As-Found Minimum Pathway 0.35scfh As-Found Maximum Pathway 8.85 scfh As Left Test Data Total Number of Valves to Test 105 Number of Valves Tested 18 Percent of As-Left Complete 17.14%

Total As-Left Leakage 3.20 As-Left Minimum Pathway 0.0 scfh As-Left Maximum Pathway 3.20 scfh Of the seventy-nine (79) valves tested to date only three (3) have any leakage. The one valve with leakage above the administrative limit is instrument air valve 2-IA-250. This valve had been planned to be replaced with an improved valve this outage because of its leakage history. It will be removed from extended interval testing until acceptable leakage history has been established (i.e., It will tested more frequently). The as-found test is not required for a valve to be replaced but was done for additional confirmation of the need for replacement. The sister valve on Unit 1 has already been replaced and is performing well. The excellent results of Type C testing on a large sample of Unit 2 valves is further indication that Unit 1 and 2 Containment Integrity was not impacted by the seismic event.

Normal as-found testing on major penetrations such as the purge valves, fuel tube and equipment hatch as Unit 2 entered the refueling outage have been satisfactory. Normal as-left testing, as Unit 1 prepares for startup, on the largest penetration, the equipment hatch has been satisfactorily completed.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 13 of 38 Electrical

1. Explain how VEPCO has determined that all electrical equipment, including electrical equipment that was commercially dedicated by the licensee as well as including the safety-related batteries, required to function during and following a seismic event (OBEISSE) remains qualified to perform their required safety-functions during all design basis events.

2. Explain how VEPCO has determined that electrical connections (i.e., electrical bus bars (power and control cable and wiring connections at all voltage levels), battery, contactors, etc.) maintained their electrical connection integrity to perform their requiredsafety-functions under both normal and accident conditions and also during and following anotherseismic event (OBE or SSE).

3. Explain how VEPCO has determined that support features associatedwith bus bars, battery racks, switchgear, cable raceways, containment electrical penetration assemblies, etc., are adequate to enable electrical equipment to perform their requiredsafety-functions under both normal and accident conditions and also during and following anotherseismic event (OBE or SSE).

Dominion Response (1, 2 and 3)

Consistent with EPRI-NP-6695, Dominion developed a methodology for performing inspections to assess significant physical or functional earthquake-related damage to SSCs. Using this methodology, inspections were performed on electrical systems and components. The inspections did not identify any significant physical or functional damage to the systems and components that would render them incapable of performing their design functions. A more detailed discussion of the attributes of the inspections and tests performed on North Anna plant SSCs to assess the potential earthquake damage is contained in Dominion's letter dated September 17, 2011. The following is an excerpt concerning inspection of electrical equipment:

For the 4160VAC, 480VAC, Vital/Semi-Vital 120VAC, and 125VDC equipment, the areas of focus consisted of four systems: Emergency Electrical (EE), Vital Bus (VB),

Battery (BY), and Electric Power (EP). Comprehensive external inspections were performed in accordance with station procedure 0-GEP-30, "Post Seismic Event System Engineering Walkdown." Attachment 1, "Post Seismic Event Walkdown Checklist," of 0-GEP-30 contains the focus areas of these inspections for each type of equipment. In addition to the external inspections, an internal inspection was performed on the above mentioned equipment. This inspection was divided into categories of safety related systems and non-safety related systems. Safety related systems received nearly 100%

internal inspections. For the non-safety related systems (EP), a sample of 10-15% of electrical cubicles in each Motor Control Center, which contained various types of breakers and are located in several different plant locations and elevations, were internally inspected. Focus areas of the internal inspections were as follows: 1) Wiring

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 14 of 38 pull-out from terminal blocks, 2) Damaged insulators (porcelain, ceramic, or plastic),

3) Wiring pull-out from lugs, 4) Wiring harness spacing issues, 5) Backed out or missing hardware from electrical bus work, 6) Foreign material, 7) Components that have become loose from electrical sockets, 8) Insulator damage to conductors, 9) Signs of electrical flashover, 10) Odd smells or sounds of resonance, and 11) Mechanical and electrical misalignment. The inspection results were documented in the applicable inspection logs included in the procedure, and identified discrepancies were entered into the Corrective Action System. No significant physical or functional damage attributable to the earthquake was noted.

In addition to the inspections noted above, the following information relates to further assurance that electrical equipment remains fully functional following the seismic event:

Batteries The potential area of concern for hidden damage for batteries is that aged batteries (generally 10 years and older) have increased seismic vulnerability. There are twelve (12) safety related battery sets at North Anna and several non-safety related battery sets. In response to the August 23, 2011 earthquake, an evaluation for potential hidden damage for the various installed battery banks was performed. Information used in the evaluation includes the seismic testing performed to qualify the batteries, thermography scans of associated batteries, inspection information, and test results. The battery banks included in this evaluation, along with their associated installation dates, are shown below:

Mark Number Common Name Installation Date 01-BY-B-i-I-UNIT 1i-I Station battery bank Fall refueling outage (RFO) 2001 (10 years) 01-BY-B-I-Il-UNIT 1-11 Station battery bank Spring REQ 2003 (8.5

_____________________ _____________________years)

Spring REQ 2003(8.5 01-BY-B-l-Ill-UNIT 1-111 Station battery bank years) 01-BY-B-i-IV-UNIT i-IV Station battery bank Fall RFO 2004 (7 years) 01-EG-B-01A-BATTRY 1H Emergency Diesel Generator (EDG) battery bank Fall REQ 2007 (4 years) 01-EG-B-03C-BATTRY iJ EDG battery bank Fall RFO 2007 (4 years) 02-BY-B-2-I-UNIT 2-1 Station battery bank Fall RF 2002 (9 years) 02-BY-B-2-11-UNIT 2-11 Station battery bank Fall RFO 2002 (9 years) 02-BY-B-2-111-UNIT 2-111 Station battery bank Spring REQ 2004 (7.5 Spring REQ 2004 (7.5 02-BY-B-2-1 V-UNIT 2-IV Station battery bank years) 02-EG-B-02B-BATTRY 2H EDG battery bank Spring REQ 2007 (4.5 02-E-B-0B-BATRYyears)

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 15 of 38 Mark Number Common Name Installation Date Spring RFO 2007 (4.5 02-EG-B-04D-BATTRY 2J EDG battery bank years) 00-AAC-B-1-BATTRY Station Blackout (SBO) diesel August 2008 (3 years) 00-AAC-B-1-BATTRY __generator battery 01-BY-B-6A and 68-UNIT Technical Support Center November 2008 (3 years)

___ ___ __ I (TSC)_battery I _ _ _ _ __ _ _ _ _

Thermography has been performed as recommended by EPRI as a way to provide evidence of emergent degradation on the listed battery banks with no abnormal results identified. Visual inspections of the batteries have been completed with no indications of any external damage noted. This inspection includes rack anchorages and feeder cable tie wraps, along with any visible internal damage such as no excessive plate sediment in the bottoms of cells following the seismic event. Also, no leaking electrolyte has been observed on the floor or tops of any cells, which provides reasonable assurance that no hidden battery case cracking occurred as a result of the seismic event. The SBO and TSC battery banks are non-seismic, and therefore are not installed in a rack with any additional restraints to prevent shifting or tipping of the batteries. The same is true for the North Anna battery storage location in Warehouse 7 which houses replacement station and EDG batteries among many others. No shifting or tipping of any cells occurred in these locations, thus, supporting the low energy level imparted to the batteries by the August 23, 2011 earthquake.

Battery cell parameters, including temperature, specific gravity, electrolyte level, and individual cell voltages, have been measured for the Unit 1 battery banks with no abnormal or adverse trends noted from pre-seismic event results. Of particular interest are the individual cell voltages where unusually lower cell voltage readings could provide indication of internal, non-visible plate shorting or cracking, which could have resulted from the potential seismic jarring motion. These same Technical Specification Category "B" cell parameter measurements have been made for the Unit 2 "J" train batteries with no abnormal results identified. Unit 2 "H" train batteries will be measured prior to Unit 2 start up as required by normal refueling outage testing. Modified performance discharge testing per TS 3.8.4 for the Unit 2 "J" train batteries (2-111, 2-IV, and 2J EDG) has been completed with no adverse trends noted. No abnormally low cell voltages occurred in any modified performance discharge testing completed to date, further supporting the conclusion that no internal, non-visible plate damage occurred. Unit 2 "H" train batteries (2-1, 2-11, and 2H EDG) will have modified performance discharge testing performed prior to Unit 2 restart.

The North Anna main station batteries were seismically qualified by a shake table test.

The testing was conducted by Wyle Laboratories and the results are documented in associated test reports. These test reports document the seismic qualification of the installed Yuasa Exide 2GN-23 Batteries in accordance with IEEE Std. 344-1975/1987. In

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 16 of 38 addition, the environmental qualification of the same model batteries include seismic shaker table testing of 20 year-aged batteries.

The Test Response Spectra (TRS) envelop the vendor's Required Response Spectra (RRS) with a margin for the OBE and DBE tests conducted. The vendor's RRS also envelops the North Anna Floor Response Spectra (FRS) for the 294' elevation of the Service Building with substantial margin (as shown below). The vendor's test configuration is conservative since the rack used is only fixed to the seismic table at the base. At North Anna, the racks are supported at the upper tier via welds to a structural angle securely mounted to the walls of the battery rooms. This makes the rack rigid for the amplified region of the North Anna DBE spectra. Therefore, little or no amplification through the rack is expected.

Vendor RRS (WYLE Report 46647-1) vs.

Dominion Floor Response Spectra for 294' Service Building (2% DBE) 10 1' * *' m1[mHorl RRS(%1

• el-ývert RRSj2%)

-SB 294'2% DOENORTH-SOUTH 0S2942%DSENRIT) 0.1 ,

1 10 100 Frequency DHU]

Note: The above plotted RRS accounts for the WYLE test table machine limits, which were superimposed on the RRS figure in the test report.

The qualification levels documented in the vendor's analysis envelop the seismic demand corresponding to the installed location of the equipment for North Anna's design basis earthquake. Although there are no recordings of the earthquake motion from the August 23, 2011 event at elevation 291' of the Auxiliary Building, based on other recordings it is expected that in the more damaging frequency range of 2 to 10 HZ, the spectral peaks from the event would have been below the qualification levels discussed above.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 17 of 38 The station batteries are seismically qualified for one DBE-level shake. However, there are some key differences between seismic qualification testing and the actual August 23, 2011 event that should be considered.

- The seismic simulation testing sequence, which was conducted in accordance with IEEE Std. 344, requires five (5) OBEs and one (1) DBE test. Therefore, fatigue was induced in the batteries by the time they were tested for the DBE level. Note that per IEEE Std. 344-2004, as endorsed by RG 1.100, Revision 3, it can be stated that in terms of fatigue or equivalent strong motion cycles, five (5) OBEs are approximately equivalent to one DBE. Therefore, the batteries are acceptable for a minimum of another DBE event consistent with the IEEE Std.

- The seismic qualification testing documented in the test reports is conservative compared to Dominion's site specific requirements (as shown above in the figure).

Note that the same RRS were used for both tests. As reported in Dominion's letter dated September 17, 2011, based on comparison between the recorded data from the North Anna Unit 1 Containment basemat and the design DBE curve, the design basis was exceeded between 2 to 10 Hz by an average of 12% in the North-South direction and 21% in the vertical. It is expected that in-structure response spectral exceedances will correlate to the basemat comparison. A maximum increase in response is therefore considered over the design response spectra. By review of the Wyle seismic qualification report, there is at least 21% margin between the North Anna design requirements for the 294' elevation of the Service Building and the Test Response Spectra (TRS).

- The duration of the seismic simulation shake testing was 30 seconds. For the August 23, 2011 earthquake, the effective strong motion duration was limited to:

1 second in the North-South direction, 3.1 seconds in the East-West, and 1.5 seconds in Vertical.

- Further, in the environmental qualification report, batteries aged 20 years were shake tested to Wyle's test level. North Anna's oldest safety related battery is about 10 years old.

Dry Transformers The potential area of concern for hidden damage for dry transformers is that large internal coils without lateral bracing may have been damaged. The "large" dry transformers at North Anna are associated with 4160/480V conversion. External inspections of the transformers were completed with no discrepancies noted. There was no discoloration, damage, smell or other problems identified. There was no loosening, damage, or other problems around peripheral components such as connections, supporting insulators, external cables, etc. In addition, monitoring of voltages, temperatures, noises, etc., has not identified any concerns. Also, two dry transformers (2J and 2J1 - 4160/480V) have been opened for internal inspections. These safety related transformers were chosen because they are older, had scheduled planned

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 18 of 38 maintenance, and are located at different elevations/buildings, to provide a representative sample. The inspections were performed by the system engineer in accordance with station procedure O-GEP-30, "Post Seismic Event System Engineering Walkdown." No damage was identified during the inspections.

Electrical Connections Concerns over the adequacy of electrical connections following an earthquake generally involve electrical connections with little or no flexibility. Differential motion between the electrical equipment and stiff electrical cables could potentially cause electrical connections to loosen as a result of extending attached cables beyond their normal ranges or by the cyclic loading of an earthquake. Inspections for this type of damage were recommended by the EPRI Expert Panel Team for the Japanese Kashiwazaki-Kariwa (K-K) nuclear plant following the magnitude 6.6 earthquake in 2007. However, the K-K plant did not identify any damage of this type in the electrical connections they inspected.

Such electrical connection damage is unlikely at North Anna as well. By design, new electrical installations are installed per North Anna's electrical cable installation specification (NAS-3014) to ensure adequate flexibility for installations serving safety related, seismic equipment, as stated in the excerpt below.

6.2.4.11 Cables which serve Safety Related equipment which is subject to requirements for seismic protection require flexibility and slack at transition points between raceway sections of different types, and between raceways and equipment. Cable installation at such points under the conditions outlined shall be in strict accordance with the applicable Design Document. The unsupported length of cable or cable in flexible conduit shall be not less than 24 inches nor greater than 5 feet, except as otherwise specifically noted.

Further, safety related electrical equipment within the scope of Unresolved Safety Issue (USI) A-46 (Generic Letter 87-02) was inspected per the requirements of the Seismic Qualification Utility Group (SQUG) Generic Implementation Procedure (GIP). The GIP requires checking for adequate flexibility for all electrical connections.

Following the August 23, 2011 earthquake, employing the EPRI Expert Panel recommendations, a sampling of electrical connections were 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

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 19 of 38 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 reports of a loose connection in any of the testing or inspections'performed after the seismic event. Visual inspections internal to emergency electrical and electrical power system components (breakers, process racks, etc) were performed in accordance with station procedure 0-GEP-30 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.

6. Explain how VEPCO has determined that the neutron flux instrumentationfunctioned in accordance with the design requirementand that the trip was valid.

Dominion Response Reference Dominion's letter dated September 27, 2011, which details (Attachment 1 Section III) the response of the Nuclear Instrumentation for the dual unit trip following the Magnitude 5.8 earthquake. The following is a summary:

"The North Anna units experienced a decreasing reactivity trend that, when combined with the seismically induced core barrel and nuclear indication effects, resulted in the negative flux rate trip. This was an expected and desired plant response considering the magnitude of the earthquake. At no time did reactor power increase above 100% power. Installed protection equipment responded as designed."

7. Regarding the North Anna dual unit trips, how did VEPCO determine that the offsite power system has adequate capacity and capability to mitigate all design basis events and that the degradedvoltage setpoints are adequate?

Dominion Response Two main calculations determine the adequacy of the Degraded Voltage relay setpoints.

The calculation for the 4.16kV Degraded Voltage and Undervoltage relay setpoints determines the minimum relay setting to provide sufficient voltage to 4160V and 480V emergency bus loads. Generally, this means ensuring a minimum of 90 percent rated nominal voltage at the terminals of safety related loads.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 20 of 38 The calculation for the North Anna voltage profiles demonstrates that 4160V and 480V emergency bus loads have sufficient voltage, and also ensures that the emergency buses do not separate from an operable offsite power source due to premature actuation of the degraded voltage relays and timers. The calculation evaluates design basis events with various allowable electrical distribution system alignments. The design basis events evaluated are based on the review of numerous resources including the North Anna Updated Final Safety Analysis Report (UFSAR) - Chapter 8, 10 CFR 50 Appendix A - General Design Criterion 17 "Electric Power Systems," NUREG-0800, Section 8.2, Rev. 3 "Offsite Power System," and licensing correspondence including the NRC letter dated January 11, 1983, which transmitted the NRC Safety Evaluation regarding Adequacy of Electrical Distribution System Voltages for North Anna Power Station. Both single unit and dual unit events are considered.

A dual unit trip has specifically been addressed and no concerns with either adequacy of equipment voltages or separation from offsite power via the Degraded Voltage relays were identified. The impact of a dual unit trip on the preferred power supply to the Unit 1 and 2 emergency buses is limited since Unit 1 has a 22kV main generator circuit breaker. For a Unit 1 trip, Station Service Buses do not normally transfer to the Reserve Station Service Transformers. Unit 2 does not have a 22kV main generator circuit breaker. As stated in UFSAR Section 8.3, the Unit 1 main generator circuit breaker "reduces the probability of combined loading from both Units 1 and 2 normal and emergency buses on the reserve station service transformers." While the Emergency Bus voltages are expected to drop in the event of a dual unit trip, the Reserve Station Service automatic load tap changers will restore voltages prior to completion of the non-accident Degraded Voltage Relay timers, thus alleviating the threat of separation.

The Dominion calculations discussed above, demonstrate that the offsite power system has adequate capacity and capability to mitigate design basis events, and the degraded voltage setpoints are adequate.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 21 of 38 Instrumentation and Controls

1. The staff understandsthat VEPCO has been examining all unusual spurious change of state of /&C and electrical equipment that impacted the Sequence-of-Events recorders and other post-trip review logs from the August 23, 2011 event, and that the NRC staff AIT members are evaluating the licensee's actions in thoroughly investigating the root causes of unexpected equipment performance in this area.

Describe how these unexpected instrumentation issues were resolved.

Dominion Response Dominion's letter dated September 27, 2011 details (Attachment 1,Section III) the response of the Nuclear Instrumentation as evaluated by the Root Cause Team for the dual unit trip following the Magnitude 5.8 earthquake. As part of that Root Cause Evaluation, all unexpected instrumentation responses were also evaluated. Subsequent investigation determined that the alarms were valid for the existing plant conditions.

2. The licensee's presentation to the NRC staff on September 8, 2011, identified that "comprehensive surveillance testing to validate SSC operability/performance"(448 surveillance tests) will be performed. The staff would like to understand the basis for selection of the particularI&C-related surveillance tests that are scheduled to be performed (or were performed) and whether the licensee has identified any additional acceptance criteria for such testing that may require additional field confirmations or additional test steps to be performed during such surveillance testing.

For example, some RTS and ESF periodic functional testing is performed without including the local transmitterin the loop, and some locally-mounted instrumentation devices have flexible conduit connections. Should these connections be subjected to seismic acceleration in key natural frequencies of the flexible section that are in excess of design basis conditions, the additional stress put on the instrument terminals could weaken the electrical connections at the terminal strips of the devices, which could result in momentary disruption of the signal, but not permanent disruption that would manifest itself under the static conditions normally present during a periodicsurveillance test.

a. Describe how potentially loose electrical and/or mechanical connections were addressed.

Dominion Response to Part a The response to this question is provided in the answer to Electrical Question No. 2 above.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 22 of 38

b. Describe how the verification of the safety related instrumentation (especially mechanical instrumentation) calibration remained within the specification limits was performed.

c. Describe how the verification of the safety related instrumentation channel response times remained within the specification limits was performed, (especially the settings of mechanically-based instrumentation devices and relays, e.g., Agastat time delay relays, resulting in a total channel response time that could exceed analyzed event response time requirements).

Dominion Response to Parts b and c 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.

3. The staff requests the licensee to confirm that the plans for start-up testing of each unit include confirmation of proper operation of non-safety, but important to safety control systems, such as would be performed as elements of the pre-operationaland power ascension testing described within Appendix A to Revision 3 of Regulatory Guide 1.68 to verify proper operabilityof the normal (non-safety related)plant control systems (e.g., feedwater control, rod control, pressurizerlevel and pressure controls, secondary system steam pressure control system, main turbine and feedwaterpump turbine control systems, in-core instrumentation, plant annunciator and process computer systems, seismic instrumentation system, plant instrumentationgrounding system, etc.).

a. Confirm which non-safety but important-to-safetyplant systems were identified by the licensee as critical to the safe operation of the plant.

b. Confirm what pre-operational testing has been selected to confirm proper operabilityof these systems priorto start-up.

c. Identify what sequence of testing and administrative controls will be utilized during the planned power ascension during restart to ensure that such systems are properly operatingbefore increasingto the next power level.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 23 of 38 Dominion Response (3a and b)

The following discussion details the I&C testing that has been done, or that is in progress for essential NSSS Protection, Control, and Miscellaneous Systems, for North Anna Units 1 and 2 in preparation for post-earthquake startup.

Please note that since some task items are in progress, the term "will be" (used in this response), denotes the scope of the items that will have been completed, once the items on the "I&C Work Lists" as described have been completed.

North Anna Unit 2 Protection The 18-month Channel Calibration will be performed on the Unit 2 Reactor Trip System (RTS) and Engineered Safety Features Actuation System (ESFAS) instrumentation. The 18 month Channel Calibration verifies the operability of the loop transmitter(s)/remote sensor(s), active/adjustable 7300 circuit cards, indicator(s), recorders, control room alarms, trip status indicators, computer points, and channel test/bistable test switches.

Control The 18-month Channel Calibration will be performed for the essential NSSS Control Systems, which includes:

" Steam Generator Level Control,

• Pressurizer Pressure and Level Control,

" Steam Dumps

" TAVG Rod Control and Power Mismatch

" Feedwater Bypass Flow Control

" Steam Generator Atmospheric Relief Valve Control

" TAVG Deviation Alarms and Median Select Circuits The 18-month Channel Calibration for a control system verifies the operability of the loop transmitter(s)/remote sensor(s), active/adjustable 7300 circuit cards, Manual/Auto Stations, indicators, recorders, control room alarms, computer points, test switches, and final control elements with their attendant instrumentation.

Miscellaneous For Unit 2, other instrumentation that is important to plant safety and operation will be calibrated using the appropriate Instrument Calibration Procedure (ICP).

Examples of this instrumentation include:

• Tank level indications - which include: Refueling Water Storage Tank (RWST),

Emergency Condensate Storage Tank (ECST), Casing Cooling, Volume Control

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 24 of 38 Tank (VCT),Chemical Addition Tank (CAT), Steam Generator (S/G) wide range (WR) Level, Pressurizer (PZR) WR Level, and Reactor Vessel Level Indication System (RVLIS)/Inadequate Core Cooling Monitor (ICCM),

" Pressure indications - for example: RCS WR Pressure - NDT, Feedwater (FW)

Header Pressure, Loop Fill Header Pressure, etc.,

" Flow indications - for example: RHR Flow, RCP Seal Leakoff Flow, Safety Injection Flow, Main FW Pump Recirculation Flow Control, etc.,

• Radiation Monitoring Systems- which include Steam Line Radiation Monitors, Loop Noble Gas Effluent Monitor, Containment Radiation Monitor, N-16 Leak Rate Radiation Monitor, and Condenser Air Ejector Radiation Monitor, Balance of Plant (BOP) items - which include: Electro-Hydraulic Controls (EHC),

Turbine Generator Core Monitor Temperature, Instrument Air System, Nitrogen System, S/G Blowdown, and ATWS mitigation system actuation circuitry (AMSAC).

Similar to the Control Systems discussed above, the ICP verifies the operability of the loop transmitter(s)/remote sensor(s), active/adjustable electronics, Manual/Auto Stations, indicators, recorders, control room alarms, computer points, test switches, and final control elements with their attendant instrumentation.

When the calibration and tests identified above are completed, North Anna Unit 2 will have verified the operability of the critical instrumentation in NSSS Protection, NSSS Control, and Balance of Plant Instrumentation and will be prepared for plant start-up.

North Anna Unit 1 Protection The 18-month Channel Calibrations were performed for the Unit 1 Reactor Trip System (RTS) and Engineered Safety Features Actuation System (ESFAS) instrumentation, and Solid State Protection System (SSPS). The 18-month Channel Calibrations verified the operability of the loop transmitter(s)/remote sensor(s),

active/adjustable 7300 circuit cards, indicator(s), recorders, control room alarms, trip status indicators, computer points, and channel test/bistable test switches. No anomalies were identified during this testing.

Control An 18-month Channel Calibration was performed for the Pressurizer Level Control System. This is considered to be acceptable without additional checks based on a comprehensive review and analysis of the out of tolerance/out of specification review on I&C components that was performed as discussed in the Summary Section below.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 25 of 38 Miscellaneous Other important Unit 1 instrumentation that is important to safety was calibrated using the appropriate ICPs. Examples of the Unit 1 instrumentation that were calibrated or functionally checked include: AMSAC, NDT Overpressure. Protection, Safety Injection Flows, ICCM, Vibration and Loose Part Monitoring, Seismic Monitoring System, EHC, Turbine Overspeed Protection, and Radiation Monitoring Systems.

Summarv A review of I&C-related out of tolerance and out of specification Condition Reports for transmitters, 7300 cards, and various miscellaneous instrumentation was conducted, and is on-going, as work proceeds. It encompasses the information available for each unit for the post-earthquake outages (to date), and for the two (2) previous outages on each unit. No adverse trends (numbers, nor magnitude of adjustments), or anomalies were noted during this review.

Dominion Response to Part 3c To ensure proper response of the reactor core and proper adjustment of nuclear instrumentation, Unit 1 will hold at less than 30% power to perform core flux mapping and analysis of core response. Unit 1 will also hold at 75% and 96% power to validate proper core response and adjust nuclear instrumentation as necessary. Unit 2 will also perform the normal plant ascension testing for a refueling outage, which includes holds at 30%, 75%, and 96% power.

Each unit will perform control rod system logic and timing tests to ensure proper system operation. Control rod drop time measurements will be performed above 500 degrees F to ensure proper insertion times.

Each unit will follow normal plant startup protocol, which includes functional checkout of various systems including: steam generator water level control system, boration control systems, rod control system, main turbine speed and load control, main steam dump system, turbine extraction steam and feedwater heating control systems, and RCS pressure and temperature control. As part of the plant heatup and power escalation process, instrumentation channel checks are performed and documented by control room personnel to ensure proper instrumentation response.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 26 of 38 Fire Protection

1. Describe how you have verified or confirmed the functionality following the earthquake of the fire protection structures, systems and components, both passive and active, that are credited in your approved fire protection program or are relied upon to ensure safe shutdown in the event of a fire.

2. Describe plant staff activities that have been conducted (testing, etc.) subsequent to the earthquake. Identify any discrepancies found as a result of these activities that may have affected functionality or indicateda need for repairs.

3. Please include plant staff activities related to assuring functionality of automatic and manual fire protection systems and fire-fighting equipment.

4. Please also indicate if there were fire protection system actuations, detection system signals or other fire protection relatedindicationsdue to the earthquake.

Dominion Response (1, 2, 3, and 4)

Consistent with the EPRI NP-6695, "Guidelines for Nuclear Plant Response to an Earthquake," North Anna developed a methodology for performing inspections to assess significant physical or functional earthquake-related damage to structures, systems, and components (SSCs). Using this methodology, inspections were performed on the Fire Protection (FP) System. The inspections did not identify any significant physical or functional damage to the system that would render it incapable of performing its design functions. A more detailed discussion of the attributes of the inspections and tests performed on North Anna plant SSCs to assess the potential earthquake damage is contained in Dominion's letter dated September 17, 2011.

A Reasonable Assurance of Safety (RAS) was written to document the functionality of the FP System following the seismic event. The RAS evaluation evaluated aspects of the FP/Appendix R system (seismic or non-seismic) to determine reasonable assurance that the system met its functional requirements without the need for further compensatory actions.

Based on performance monitoring of the FP System since the seismic activity, it has been concluded that the FP Instrumentation, Suppression System, Detection System, and Passive FP barriers are capable of performing their design functions. Engineering performed thorough inspections of the FP Systems to support this determination as noted above. The guidance of Fire Protection/Appendix R implementing procedure, applicable periodic tests (PTs), periodic maintenance procedures and TRM requirements were used to determine functionality acceptance during the inspections and other evaluations.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 27 of 38 The fire pumps were checked on operator rounds and have shown no damage since the seismic activity, and the fire pumps have had surveillance testing performed to further demonstrate functionality. Surveillance tests demonstrated that the fire pumps meet their functional requirements. The FP pressure maintenance (jockey) pump has not been operating more frequently than before the earthquake. This indicates that fire protection hydraulic piping integrity has not been breached by the seismic event. This includes fire mains, fire valves and standpipes. The fire hydrants and deluge systems are dry systems and were visually checked. In addition, FP valves, hydrant and hose station valve positions have been verified functional in accordance with station procedures. Due to the robust construction of these valves, it is reasonable to assume that there has not been any disk to stem separation and the valves are functional.

For the sprinkler systems, inspections have identified only minor deficiencies, which have been resolved through the work order process. As stated above, no unusual operation of the FP jockey pump has been observed indicating that the sprinkler system piping integrity is intact. This provides indication that the fire protection hydraulic system meets functional requirements.

Carbon Dioxide (CO,) system (TRM 7.1.2, 7.1.3)

Visual inspection of the C02 system piping in accordance with O-GEP-30 has determined that there are no structural deficiencies due to the seismic event. The main generators were purged in accordance with station procedures. This indicates that the C02 system is available if needed for fire extinguishment. The electrical control cabinets for the CO 2 system are robust in construction. A representative sample of CO 2 control cabinets was inspected. Circuit boards, terminal strips, relays and internal wiring were verified intact and in excellent condition. They were found to fully meet functional requirements. Based on the C02 system performance and visual inspection, the C02 system meets its functional requirements.

Halon systems (TRM 7.1.4)

The Unit 2 Main Control Room Halon System was tested and no deficiencies were noted during performance of this test. Similarly, the emergency switchgear halon discharge nozzles were also observed and no discrepancies noted. Since no deficiencies were found, the halon systems meet functional requirements.

Fire doors (TRM 7.2. 7.11), Fire dampers (TRM 7.2, 7.11) and Penetration Fire Seals (TRM 7.2)

Plant inspections were conducted to verify functionality of the fire doors, dampers and penetration seals in Unit 1 Containment, Units 1 and 2 Emergency Switchgear Room, Units 1 and 2 Cable Vault and Tunnel, Units 1 and 2 Cable Tray Spreading Room, Unit 2 Quench Spray and Unit 2 Safeguards fire areas with no deficiencies found. Station procedures were used as a guideline for performing these inspections, and the 0-GEP-30 walk down procedure was used to document the inspection performance. No

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 28 of 38 deficiencies were found, therefore, these passive systems meet their functional requirements.

Fire walls and barriers (TRM 7.2, 7.11) and structural steel fire coating Visual inspections of these structures were completed by civil engineering personnel and were documented. Only cosmetic damage has been found to these structures. Fire protection engineers examined several of these minor cracks. There is no passage of air or light and fire barrier integrity has not been jeopardized by this cosmetic damage.

The work order process is being used to complete repairs as required. There have been some log entries regarding rattle space seals in the open joint between the Cable Vault floor (Elev. 259') and the Auxiliary Building mechanical penetration area below (Elev.

244'). The HVAC system engineer and the FP system engineer examined these seals and found them to be intact. Based on the above inspections, fire walls and barriers meet their functional requirements in the present condition.

Cable tray covers, conduit seals, conduit fire wraps, radiant energy shields and cable tray firestops were inspected in the containments. No deficiencies were found; therefore, these components meet their functional requirements.

The Control Room alarm panel (smoke / heat detection and fire alarms) 1-FP-CPU-IMS-2 Simplex network is a supervised network compliant with NFPA-72. This means that each detector is addressable through the network and constant self-checks are automatically performed by the system. Any loose connector base, open circuit or shorted wires will create a malfunction alarm. It was determined through observation that there were no abnormal conditions with the fire detection or alarm instrumentation.

It was therefore concluded that FP/Appendix R fire detection instrumentation meets functional requirements.

Immediately following the earthquake, a sprinkler head in the Unit 2 turbine building was noted to have actuated. No fire was present. The sprinkler was isolated. Repairs were completed on August 25, 2011. Approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> after the earthquake, the Unit 2 "A" Main Transformer deluge actuated. No fire was noted and the system was isolated. Repairs will be completed prior to Unit 2 restart. No other FP systems actuations were noted as a result of the earthquake.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 29 of 38 Appendix R / Fire Protection Systems: Functional Validation Table System Functional Validation

........ ,A ppe nd ix S y tem s Appendix R Emergency Lights Lights were verified to operate during LOOP following event Appendix R Instrumentation Verified on Plant Computer System RCP oil collection enclosures Oil collection system walk-down using 1-PT-1 08.5 / 0-GEP-30 Appendix R alternate indication Operator rounds LOG-6D indicates normal Appendix R Alternate Shutdown Equipment Alternate Shutdown equipment verified to be available Appendix R communication Appendix R radio checked for functionality ManuaSkystems .$.. ...

Fire extinguishers Accountability verified Hose houses Verified lAW 0-PT-1 00.3 Fire hose racks Accountability verified

'. .L. . +.Detecion Systems .. ,

Smoke/heat detection systems Control room alarm panel validation and visual inspection Fire Alarm Systems Control room alarm panel validation and visual inspection Hydraulic Su"r sso n Sprinkler systems Piping integrity verified - no leakage Standpipes Verified lAW 0-PT-1 00.3 Fire Pumps 1-PT-100.1.1, 0-PT-101.1A, 0-PT-101.1B, 1-PT-100.1.2 SAT Fire Mains Piping integrity verified - no leakage Fire valves Verified lAW 0-PT-1 00.3 Hydrants Verified lAW 0-PT-100.3 Deluge systems Verified lAW 0-PT-100.3

.:Gas Suppression Carbon Dioxide (CO 2) systems Visual inspection lAW 0-GEP-30, 1/2-OP-43.1 Halon systems Visual inspection lAW 2-PT-107.2 IPI :. Passive.Fire.Protection .

Fire doors Visual inspection lAW 0-GEP-30 Fire dampers Visual inspection lAW 0-GEP-30 Fire walls and barriers Visual inspection lAW 0-GEP-30 Penetration Fire Seals Visual inspection lAW 0-GEP-30 Cable Tray Covers Visual inspection lAW 0-GEP-30 Conduit Seals Visual inspection lAW 0-GEP-30 Structural Steel Fire Coating Visual inspection lAW 0-GEP-30 Conduit Fire Wraps Visual inspection lAW 0-GEP-30 Radiant Energy Shields Visual inspection lAW 0-GEP-30 Cable Tray Fire stops Visual inspection lAW 0-GEP-30

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 30 of 38 PRA

1. Was the functionality of any non-safety relatedequipment, creditedin a risk-informed license amendment, considered as part of the restart plan? If not, what is Dominion's approach to ensure the continued adequacy of such risk-informed license amendments?

Dominion Response Risk-informed license amendments have been reviewed to determine whether credit was previously given for non-safety related equipment to support the risk informed amendments. The station blackout (SBO) diesel was determined to be the only risk-informed amendment for which non-safety related equipment was credited in the risk assessment. The use of the SBO was documented in Amendments 214 and 195, dated August 26, 1998, that extended the emergency diesel generators (EDG) allowed outage time to 14 days for one EDG if the SBO diesel and the opposite unit's EDGs are operable.

During the August 23, 2011 earthquake, the SBO diesel started and was subsequently used to provide power to an emergency bus for several hours. Since then the SBO diesel has been visually inspected, which included the engine, motor control centers, and related bus work. The SBO diesel is considered fully functional.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 31 of 38 Steam Generators

1. Describe the evaluations, inspections, and analyses (if any) of the steam generators to ensure the steam generator (SG) supports, tubes, and other internals (tube support structures, steam separation equipment, j-nozzles, wrapper and wrapper supports, blowdown piping, etc) will function as designed. If a sample inspection were performed, please provide justification for limiting the scope of the inspections.

Please discuss the results of the inspections highlighting any differences observed since the last inspections.

Dominion Response As noted in Dominion's letter dated September 27, 2011 (Serial No. 11-520A), EPRI Steam Generator Management Program Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7, Section 3.10, states that forced outage examinations shall be performed during plant shutdown subsequent to seismic occurrence greater than the OBE. The guidelines require performance of a 20% sample inspection of Unit 1 and Unit 2 steam generator (S/G) tubes. This inspection criterion was exceeded for Unit 1 by performing a 100% tube inspection of the "A" S/G and was exceeded for Unit 2 by performing 100% tube inspections of S/Gs "A" and "C" which were previously scheduled to be performed during the current refueling outage. The inspection results for the Unit 1 "A" S/G were provided in the September 27, 2011 letter noted above which addressed the S/G tubes and internal components on both the primary and secondary sides. The Unit 2 "A" and "C" S/G inspections were recently completed; however, the results of the Unit 2 S/G inspections are currently being assembled and reviewed. Nevertheless, no degradation was identified in the Unit 2 S/G tubes, nor were any new dents/dings identified. Detailed Unit 2 S/G inspection results will be provided in a subsequent update.

Prior to this outage, tube support plate (TSP) wear was the only degradation mechanism classified as "existing" in the North Anna Unit 1 S/G tubing. Several other mechanisms were classified as "potential" (e.g., anti-vibration bar (AVB) and foreign object wear, etc.). It is primarily these damage mechanisms that were targeted by this inspection. In addition, 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. Denting inspection results are discussed in the response to Question 3 below.

Primary side inspections included S/G tube eddy current inspections per the requirements of the EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines: Revision 7," 1013706, October 2007 and the Dominion fall 2011 Steam Generator Degradation Assessment. The tube degradation detection methods were qualified per these guidelines and were confirmed to be appropriate for use at North Anna. Three indications were identified during this inspection that are relevant to tube integrity. These were the only tubes identified with tube degradation during this

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 32 of 38 examination. The three indications were caused by shallow volumetric tube degradation at TSP land contact points and are characteristic of TSP vibration and wear. The three indications were initially identified during the 2007 inspection of S/G "A", and the depth of the three reported TSP wear flaws did not increase during the four years between the 2007 and 2011 inspections. The largest wear flaw had a maximum through-wall depth of 13 %. None of the affected tubes were plugged. No detectable AVB wear has been identified to date.

Secondary side inspections included visual examinations of the blowdown pipe, blowdown pipe supports / flow blockers, no-tube lane tie-rod, wrapper and lower jacking studs, and tube bundle periphery from the lower hand hole inspection ports above the secondary tubesheet face. These examinations revealed no evidence of structural damage or foreign objects. No degradation of secondary side internals which could impact tube integrity prior to the next examination was identified during this outage.

While ultrasonic testing exams of selected feedring locations identified one measurement of localized thinning which prompted reevaluation of the minimum acceptable wall thickness, J-nozzle visual examinations identified no evidence of actual flow assisted corrosion (FAC) advancement. The internal feedring / J-nozzle interfaces of the J-nozzles in S/G "A" were visually examined. The total number of J-nozzles was confirmed to be present. Videos from S/G "A" were reviewed side by side with videos from the previous inspection in (2007) to identify any locations where FAC may have continued to advance. This review revealed no discernible evidence of change since the 2007 inspection. No tube support deficiencies were identified; hence, there are no known conditions which could impact tube stability.

As indicated by the results of the primary side and secondary side examinations, the North Anna Unit 1 steam generators continue to satisfy the structural and leakage integrity requirements delineated in the Dominion Steam Generator Program and North Anna Technical Specifications. Specifically, no primary-to-secondary S/G tube leakage was reported during the previous operating period or in association with the seismic event. Therefore, the operational leakage performance criteria were not exceeded during the operating period preceding this outage. Furthermore, no degradation exceeding the performance criteria was identified during this or any previous North Anna Unit 1 S/G inspection. This evaluation has demonstrated that operation of the North Anna Unit 1 S/Gs until the next scheduled examination of each steam generator (fall 2013 for S/Gs "B" and "C", spring 2015 for S/G "A") will not cause the structural or leakage integrity performance criteria to be exceeded. In addition, the absence of conditions which challenge the S/G program performance criteria validates prior outage operational assessment assumptions and conclusions regarding structural and leakage integrity.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 33 of 38

3. Provide a summary of ding/dent indicationsfound and how they compare in number and size to those observed in previous inspections.

Dominion Response The Unit 1 "A" 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 RPC inspections identified only two (2) new dents in the Unit 1 "A" S/G, and both dents were at the same tube support plate (TSP 4C).

Of the dents reported during this inspection, only two low voltage dents (i.e., dents < 5 volts) were not present during the previous outage examination. Consequently, these two dents were considered to have developed during service. Both of these new dents were identified in tube SGA R46C39 and were located at the upper and lower edges of TSP 4C. The affected tube is adjacent to two tubes (SGA R46C37 and SGA R46C38) that had four new dent indications at the same location in 2007. It is noted that this group of tubes is adjacent to a TSP wedge location. The wedge may have played a role in the formation of the dents by affecting the local TSP geometry in response to the thermal expansion and contraction of S/G internals. Because of the identification of new dents in this area during the 2007 and 2011 Unit 1 "A" S/G inspections, it is unlikely the two dents identified in 2011 were the result of the August 23, 2011 seismic event. There was no evidence of change in the 2007 dents and the +Point examinations of the newly dented locations identified no tube degradation.

Also, as noted in the response to Question 1 above, no new dents/dings were identified in the inspected Unit 2 S/G "A" and "C" tubes.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 34 of 38 Snubbers

1. Confirm that a visual examination of all the snubbers (small bore and large bore) has been performed to ensure compliance with the design basis acceptance criteria. If all snubbers were not inspected, please provide the rationale for the sampling strategy.

Dominion Response Visual inspections were performed for 100% of the Unit 1 and 2 small and large bore snubbers. These inspections were performed by ASME Level II, VT-3 qualified inspectors.

2. Please confirm that an evaluation of snubbers has been performed, and how you determined whether a snubber was locked. If a snubber was determined to be unacceptable (e.g., deformation, damaged bearings,missing or broken pin, fluid leak in the hydraulic snubber, etc.) during the visual examination (item 1, above), 'please discuss the results of these evaluations.

Dominion Response Typically, hydraulic snubbers do not fail in a locked condition. Snubbers at North Anna are hydraulic snubbers. Visual inspection of snubbers includes checking the snubber for freedom of movement where possible without disconnecting the snubber. Snubbers were visually inspected as discussed in the response to Question 1 above. Several snubbers had deficiencies identified during the visual exam or by engineers performing system inspections that required further evaluation. On Unit 1, five (5) snubbers have been bench tested to confirm functionality due to low fluid levels being identified.

Several other Unit 1 snubbers had minor issues that were evaluated to not impact functionality, but were addressed (e.g., pipe clamp slightly rotated on pipe, oil on snubber). On Unit 2, additional snubbers are to be functionally tested due to visual inspection deficiencies. Based on past experience, these snubbers are expected to pass the functional tests; however, these tests have not been completed at this time.

Additionally, several other Unit 2 snubbers had minor issues that were evaluated to not impact functionality, but were addressed (e.g., pipe clamp slightly rotated on pipe, oil on snubber, missing pin spacer).

3. Please confirm that an evaluation of snubber(s) has been performed for snubbers located on an unacceptable or damaged piping system discovered during the inspection of the piping system. Please discuss the results of these evaluations.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 35 of 38 Dominion Response There were no unacceptable or damaged piping systems identified during the system inspections.

4. Please confirm that the testing of snubbers (small bore and large bore) as required by Technical Requirement Manual (TRM) Section 3.7.5, has been performed to ensure the operability of all the snubbers. [NRC authorized the use of alternative TRM Section 3.7.5 in lieu of the ASME Code requirements in the safety evaluations for Relief Request CS-001 for North Anna Unit I (ADAMS # ML091350058 dated June 10, 2009) and Relief Request N2-14-CG-001 for North Anna Unit 2 (ADAMS #

ML110260022 dated January28, 2011)]. Please confirm that snubbers tested during the initial visual examinations (Item 1, 2 and 3) were not included in the sample test performed per the TRM.

Dominion Response Functional testing of the snubbers is being performed in accordance with the normal refueling outage procedure for Unit 2. This will meet the TRM surveillance requirements. Sixteen of the planned sixty (60) Unit 2 functional tests, to meet TRM requirements for small-bore snubbers, have been completed with no test failures. This functional test group is pre-determined within the functional testing procedure. Neither of the two large bore snubbers that are planned for functional testing has been tested yet. Snubbers tested due to visual inspection deficiencies do not count towards the required functional test group to meet TRM requirements.

In addition to the TRM functional test group, five (5) snubbers on Unit 1 have been functionally tested due to low fluid levels identified during the visual examination. An additional five (5) snubbers are planned to be functionally tested on Unit 2 due to low fluid levels identified during visual examination. Altogether, North Anna will have functionally tested more than seventy (70) snubbers at the end of this effort.

Note that Unit 1 and Unit 2 are similarly designed and constructed plants. The piping systems are similarly arranged and supported. Both units are on the same elevations and have similar design response spectra. Both units experienced identical ground motion from the seismic event. Based on these similarities in design and construction, it is expected that snubbers on both units were impacted by the earthquake similarly.

Therefore, functional test results for Unit 2 are representative for Unit 1. Any functional test failure requires a cause evaluation in accordance with our corrective action system.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 36 of 38 Reactor Vessel Internal (RVI) Components

1. The licensee, in Enclosure 3 of the submittal dated September 17, 2011, stated that structural loadings on the RVI components were used in its structural analysis as a part of the post-earthquake evaluation of the RVI components. The staff requests that the licensee confirm inclusion of the following RVI components in its structural evaluation: (a) Lower Support Forging; (b) Baffle Former Assembly including bolts; (c) Upper Core Plate; (d) Guide Tube; and (e) Core Barrel Assembly including bolts.

Dominion Response As noted in Enclosure 2 of the submittal dated September 17, 2011, inspection results are consistent with Damage Intensity 0 on the EPRI seismic damage scale. EPRI NP-6695 describes how prescribed inspections and tests are keyed to the severity of the earthquake. No specific inspections of reactor vessel (RV) internals or associated components are specified in EPRI NP-6695 for Intensity 0 earthquakes. Since the earthquake produced only minimal damage to non-seismically designed equipment, and since there was no significant physical or functional damage to seismically designed systems, structures, and components that were examined following the event, there is reasonable assurance that there was no significant physical or functional damage to reactor vessel internals, and that the reactor vessel internals remain functional and capable of performing their design functions.

The evaluations in Enclosure 3 of the above submittal considered the interface loadings for several key reactor vessel internals interface load points in the vessel. These evaluations of reactor vessel internals design margins were performed based on existing design analyses of the structural integrity of the reactor vessel internals. Only the loads calculated for a seismic event (either the OBE or DBE) were of interest for the evaluation. The calculated seismic-only loads were compared with allowable load limits which correspond to allowed stress limits for Upset conditions (Normal + OBE Loads) for which no deformation is allowed. This provides a more stringent criterion than is typically applied to the DBE loads when assessed in normal design calculations (UFSAR 3.9.3.1.1). This conservative criterion provides additional assurance that RV dimensions and geometry are maintained. The key interface loads evaluated satisfied this criterion.

The RV internals interface loads are those loads between the reactor vessel and core barrel, and between the fuel and core plates. Thus, the components identified in the list of Question 1 were not included in the evaluation in Enclosure 3. However, a preliminary assessment has shown the loadings from the August 23, 2011 earthquake for the lower support forging (i.e., lower support plate and lower core plate), upper core plate, and guide tubes are acceptable.

Although not required by EPRI NP-6695, Dominion in collaboration with Westinghouse identified several inspections of the reactor vessel internals to supplement the above conclusion that the reactor vessel internals remain capable of performing their design bases functions. The inspections are listed and discussed in Response to NRC

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 37 of 38 Question 8 in Dominion letter dated October3, 2011 (Serial No. 11-544A). The inspections will identify any anomalous condition of the North Anna reactor vessel internals. If any anomalous conditions are found, an assessment of the impact will be performed.

4. UFSAR Section 3.6.2.4 states that the NAPS main coolant loop piping was approved for leak-before-break (LBB) by the NRC. How have the effects of the beyond design basis earthquake loadings been evaluated to confirm that the NAPS LBB analyses are still valid, and what were the results from the evaluations.

Dominion Response The technical bases for eliminating large primary loop pipe rupture as a structural design basis for North Anna Units 1 and 2 are documented in Westinghouse WCAP-1 1163 and Supplement 1 to WCAP-1 1163. These reports were docketed in submittals to the NRC during licensing of the leak-before-break (LLB).

The following is an assessment of margin that is contained in the WCAP-1 1163 LBB analysis:

1) The maximum moment in the North Anna Primary Loop plant-specific piping is less than 60 percent the generic maximum moment used by Westinghouse in an earlier LBB study.

2) The welds in each loop for both North Anna units were reviewed and five (5) locations were selected for detailed analysis. These locations included the maximum load critical location and four (4) toughness critical locations. Clear margins to the acceptance criteria were demonstrated for the five (5) locations.

3) Each unit has leakage detection systems, which have been demonstrated by past operating experience to detect RCS leakage of less than 1 GPM with reasonable accuracy. Conservatively, leakage crack sizes were determined for the five (5) locations with a margin of 10 to the detectable leak rate (i.e., 10 GPM). The leakage size crack is determined for analysis using normal operating conditions and is not influenced by seismic loads.

4) Two sets of fracture mechanics analyses were performed. In one set, combined normal operating and seismic DBE loads were applied on a through-wall crack size equal to two times the leakage size crack. In the other set, a leakage size crack was loaded with 1.4 times the predicted combined load. In both cases, the cracks were shown to be stable with significant margin.

Serial Number 11-566 Docket Nos. 50-338/339 Attachment Page 38 of 38

5) The other areas of conservatism are:

" A margin of a factor greater than two to three exists between calculated and ASME Code allowable faulted conditions and thermal stresses.

• Using the limit load analysis method, the critical flaw size for current loading is at least 32 inches, which far exceeds the stable flaw size in fracture mechanics. Therefore, significant margin exists for global stability.

" Ample margin exists in material properties to the end-of-service life. Aged material properties were used in the analysis.

As discussed above, large margins exist to accommodate an increase of seismic load, if any. Considering that the August 23, 2011 earthquake was a short duration and low energy event, the energy imparted from this earthquake to drive a postulated through-wall crack would not have been significant.

Based upon the above, it is concluded that the evaluation supporting LBB remains valid after considering the August 23, 2011 earthquake.

During a discussion to clarify several RAI questions with the NRC Staff on September 30, 2011, an NRC staff member questioned whether the break evaluations for LBB considered seismically induced fatigue crack growth. By this response, Dominion confirms that no transient driven fatigue crack growth analysis was performed in support of LBB evaluation.