ML080950111

Response to Request for Additional Information Regarding Proposed License Amendment Request One-Time Five-Year Extension to Type a Test Interval

ML080950111
Person / Time
Site:	North Anna
Issue date:	04/03/2008
From:	Gerald Bichof Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
08-0092A, RG-1.163
Download: ML080950111 (36)

Text

10 CFR 50.90 VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 April 3, 2008 U.S. Nuclear Regulatory Commission Serial No. 08-0092A Attention: Document Control Desk NL&OS/ETS RO Washington, D.C. 20555 Docket No. 50-339 License No. NPF-7 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

NORTH ANNA POWER STATION UNIT 2 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING PROPOSED LICENSE AMENDMENT REQUEST ONE-TIME FIVE-YEAR EXTENSION TO TYPE A TEST INTERVAL In a December 5, 2007 letter (Serial No. 07-0769), Dominion requested an amendment, in the form of a change to the Technical Specifications to Facility Operating License Number NPF-7 for North Anna Power Station Unit 2. The proposed change will permit a one-time five-year exception to the ten (10) year frequency of the performance-based leakage rate testing program for Type A tests as required by Regulatory Guide (RG) 1.163. This one-time exception to the requirement of RG 1.163 will allow the next Type A test to be performed no later than October 9, 2014.

In February 2, 2008 and March 12, 2008 e-mails as documented in a March 24, 2008 letter, the NRC staff requested additional information regarding the risk analysis performed to support the five-year interval extension and the previous tests and inspections performed, as well as tests and inspections scheduled during the five-year extended period. The requested information regarding the risk analysis was provided in a letter dated March 15, 2008 (Serial No. 08-0092). The attachment to this letter provides the remainder of the containment test and inspection information requested by the NRC staff.

The information provided in this letter does not affect the conclusion of the significant hazards consideration discussion provided in the December 5, 2007 Dominion letter (Serial No. 07-0769).

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Page 2 of 3 Should you have any questions or require additional information, please contact Mr. Thomas Shaub at (804) 273-2763.

Very truly yours, d~?

Vice President - Nuclea Enclosure

1. Response to Request for Additional Information Commitments made in this letter: None.

COMMONWEALTH OF VIRGINIA COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Gerald T. Bischof, who is Vice President - Nuclear Engineering, 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

• 3 Y-::"f day of ~

i ~ ,2008.

!//(Iu" L Y/ttU Notary Public VICKI L. HULL ~

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Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Page 3 of 3 cc: U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 23T85 Atlanta, Georgia 30303 Mr. J. E. Reasor, Jr.

Old Dominion Electric Cooperative Innsbrook Corporate Center 4201 Dominion Blvd.

Suite 300 Glen Allen, Virginia 23060 State Health Commissioner Virginia Department of Health James Madison Building - i h floor 109 Governor Street Suite 730 Richmond, Virginia 23219 NRC Senior Resident Inspector North Anna Power Station Mr. S. P. Lingam NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 0-8 G9A 11555 Rockville Pike Rockville, Maryland 20852 Mr. R. A. Jervey NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 0-8 G9A 11555 Rockville Pike Rockville, Maryland 20852

Enclosure RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING PROPOSED LICENSE AMENDMENT REQUEST ONE-TIME FIVE-YEAR EXTENSION TO TYPE A TEST INTERVAL CONTAINMENT TEST AND INSPECTION North Anna Power Station Unit 2 Virginia Electric and Power Company (Dominion)

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval RESPONSE TO RE UEST FOR ADDITIONAL INFORMATI N REGARDING PROPOSED LICENSE AMENDMENT RE UE T ONE-TIME FIVE-YEAR EXTENSION TO TYPE A TEST INTERVAL

Background

The Type A Containment Integrated Leak Rate Test (ILRT), the Type B and Type C Local Leak Rate Tests (LLRT), and Containment Inservice Inspection (CISI) program collectively ensure leak-tight integrity and structural integrity of the containment. The NRC staff has determined that the following information is needed to facilitate the review of the Technical Specification (TS) amendment request for North Anna Unit 2 submitted in the Virginia Electric and Power Company (Dominion) letter dated December 5,2007.

NRC Question 1 Please provide a summary list of those containment penetrations (including their test schedule intervals) that have not demonstrated acceptable performance history in accordance with the primary containment leakage rate program.

Dominion Response Electrical Penetrations In accordance with the guidance of NEI 94-01, Rev 0, electrical penetrations with acceptable performance may be placed on a 10 year testing interval after passing three consecutive refueling outage tests. If the penetration fails a test, it is returned to the short interval (every outage) until it again passes three consecutive refueling outage tests.

Penetration Test Results (Administrative limit> 0.0555 scfh) 1A O-ring 2001 - 0.0925 seth, 2002 - 0 scfh, 2004 - 0.012 scfh, 2005 - 0.001 scfh, 2007 - 0.001 scfh (returned to extended interval) 1A Canister 2005 - 0.14 seth, 2007 - 0.005 scfh (two tests remain until eligible for extended interval) 4B 2007 - Interim tailure*, as left leakage 0 scfh (three tests remain until eligible for extended interval)

Page 1 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval 60 2007 -Interim failure*, as left leakage 0 scth (three tests remain until eligible for extended interval) 13A 2001 - 0.0925 sefh, 2002 - 0 scfh, 2004 - 0 scfh, 2005 - 0.002 scfh (returned to extended interval) 16C 2004 - 0.1 sefh, 2005 - 0.004 scfh, 2007 - 0.001 scfh (one test remains until eligible for extended interval) 22A 2004 -Interim failure*, as left leakage 0.002 scfh 2005 - 0.003 scfh, 2007 - 0.001 scfh (one test remains until eligible for extended interval) 22C 2004 -Interim failure*, as left leakage 0 scth 2005 - 0.012 scfh, 2007 - 0.001 scfh (one test remains until eligible for extended interval)

• interim failure - when the penetration back fill pressure is found at 0 psig during the monthly inspection. A leak test is performed to confirm operability.

Mechanical Type C Penetrations In accordance with the guidance of NEI 94-01, Rev 0, mechanical penetration valves with acceptable performance may be placed on a 60 month testing interval after passing two consecutive refueling outage tests. If the valve fails a test, it is returned to the short interval (every outage) until it again passes two consecutive refueling outage tests.

Some of the failures below, which are indicated in bold type, resulted in high leakage rates, but the containment leakage is based on penetration minimum pathway leakage.

In the cases of high leakage rates the other valve in the penetration is also listed to demonstrate the overall health of the penetration.

Penetration No. I Valve Admin Limit Test Results 12 2-Component Cooling (CC) -TV-200B 6" 2 scfh 2001 - 35 sefh, 2002 - 0 scfh, 2004 - 0 scfh 14 2-CC-TV-200A 6" 2 scfh 2001 - 24 sefh, 2002 - 0 scfh, 2004 - 0 scfh" Page 2 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Penetration No.1 Valve Admin Limit Test Results 31 2-Hydrogen Recombination (HC)-15 3" 1 sefh 2007 - 3 seth, Additional testing required 2-HC-TV-205A 3" 1 scfh 2002 - > 257 seth, 2004 - 1.2 sefh, 2005 - 0 sefh, 2007 - 0 sefh This valve does not qualify for extended test interval.

Other valves test results in penetration 31.

2-HC-15 2002 - 0 sefh 3" 1 sefh 2-HC-TV-205B 2002 - 2.4 sefh 3" 1 sefh 2-HC-TV-201A 2002 - 0 sefh 3" 1 scfh 2-HC-TV-205B 2002 - 0 scfh 3" 1 sefh 34 2-Fire Protection (FP)-79 4" 1.5 sefh 2001 - 29 seth, 2002 - 0.35 sefh, 2004 - 0.7 seth, 2005 - 0 sefh, 2007 - 0 sefh, This valve does not qualify for extended test interval 2-FP-81 4" 5 sefh 2001 - 3.35 scfh, 2002 - 0 scfh, 2004 - 7.0 seth, 2005 - 0 sefh, 2007 - 0 sefh, This valve does not qualify for extended test interval 45 2-Reaetor Coolant (RC)-TV-2519A 3" 1 sefh 2002 - > 257 seth, 2004 - 0 sefh, 2005"- 0 sefh, 2007 - 0 scfh Other valves in penetration 45 2-RC-162 2002 - 0 sefh 3" 1 sefh 47 2-lnstrument Air (IA)-250 2" 1 scfh, 2002 - > 257 seth, 2004 - 0 scfh, 2005*- 0 sefh, 2007 - 36 seth, Additional testing required Other valves in penetration 47 2-IA-TV-202A 2002 - 0 sefh 2" 1 sefh 53 2-Safety Injection (SI)-132 1" 1 sefh 2001 - 1.4 seth, 2002 - 2.3 seth, 2004 - 0 sefh, 2005 - 2 seth, 2007 - 4 seth, Additional testing required 2-SI-TV-200 2" 1 sefh 2002 - 1.8 seth, 2004 - 0 sefh, 2005 - 0 scfh, 2007 - 0 sefh 56C 2-Sample System (SS)-TV-202A 1" 1 sefh 2002 - > 257 seth, 2004 - 0 sefh, 2005 - 0 sefh Other valves in penetration 56C 2-SS-TV-202B 2002 - 0 sefh 1" 1 scfh Page 3 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval 89 2-Vaeuum Priming (VP)-24 6" 5 scfh 2005 - > 257 sefh, 2007 0 sefh, Additional testing required Other valves in penetration 89 2-SC-TV-203 - 2005 - 0 sefh 6" 5 scfh 93 2-HC-TV-206A 2" 1 sefh 2007 - > 257 sefh Additional testing required Other valves in penetration 93 2-CV-TV-250A - 2007 - 0 sefh 2" 1 sefh 2-HC-TV-206B - 2007 - 0 sefh 2" 1 sefh 2-CV-TV-250B - 2007 - 0 sefh 2" 1 sefh 94 2-Containment Vacuum (CV)-4 8" 2.5 scfh 2007 - 6 sefh, Does not qualify for extended test interval 2-CV-TV-200 8" 2.5 sefh 2005 - 4.5 seth, 2007 -7.5 sefh, Does not qualify for extended test interval 97A 2-SS-TV-203B 1" 1 sefh 2005 -1.5 sefh, 2007 - 0 sefh, Additional testing required 109 2-HC-TV-207B 2" 1 sefh 2005 - 6.0 sefh, 2007 - 0 sefh, Additional testing required 111 D 2-Post Accident (DA)-TV-203A 1" 1 sefh 2007 - > 257 sefh, Additional testing required Other valves in penetration 111D 2-DA-TV-203B 2007 - 0 sefh 1" 1 scfh NRC Question 2 Please provide a summary table for Type B and Type C tests (including the interval schedule dates) that are planned to be performed prior to and during the requested five-year extension period of the ILRT interval.

Dominion Response See the attached Tables.

Page 4 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval NRC Question 3 Regulatory Position C.3 of RG 1.163 recommends that visual examinations should be conducted prior to initiating a Type A test, and during two other refueling outages before the next Type A test based on a ten-year ILRT interval. Please describe, with a schedule, how you would supplement this ten-year interval-based visual inspections requirement for the requested 15-year ILRT interval.

Dominion Response Per Section 9.2.1 of NEI 94-01, Rev 0 and Regulatory Position C.3 of RG 1.163 the normal inspection requirements are three examinations in the 10 year interval. Two examinations are required during the 10 years interval with a third examination just prior to the Type A test.

In accordance with NEI 94-01, Rev 0, a general visual examination is performed of the accessible interior and exterior surfaces of the containment and components including the liner plate for structural problems which may affect either the containment structure leakage integrity or the performance of the Type A test. North Anna Unit 2 has completed the following visual examinations during the current 10 year Integrated Leak Rate Test (ILRT) interval:

• February 21, 2001

• September 18, 2002 Based upon approval of the 5 year extension to the ILRT interval, two additional examinations will need to be completed, one of which will be during the outage of the Type A test (October 2014). The other examination will be scheduled during one of the following outages:

• September 2008

• March2010

• September 2011 In addition to these examinations, general visual examinations of the containment liner are performed in accordance with the IWE Section of the ASME Code.

NRC Question 4 Please provide information relative to the findings (if any) and actions taken where existence of or potential for degraded conditions in inaccessible areas of the containment structure and metallic liner were evaluated based on conditions found in Page 5 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval accessible areas as required by 10CFR50.55a(b)(2)(viii)(E) and 10CFR50.55a(b)(2)(ix)(A).

Dominion Response North Anna Unit 2 has performed this evaluation once due to conditions found during the fall 1999 refueling outage. As required by 10CFR50.55a(b)(2)(viii)(E) and 10CFR50.55a(b)(2)(ix)(A), a condition report was made in the North Anna Unit 2's Inservice Inspection Summary Report for the Fall 1999 refueling outage dated January 3, 2000 (Serial No 99-0618). The applicable pages from this report are attached. The report details the findings and actions taken.

NRC Question 5 In Section 4.6 of Attachment 1 to the TS amendment request, it is stated that, in the first ten-year interval of IWE examinations, the areas associated with the liner damage caused by wood left in the concrete at construction have been ultrasonically examined (augmented Category E-C examination). Please provide a summary of areas other than where liner damage was caused due to wood left in the concrete that have been identified for augmented examination (if any). It is also stated that no augmented Category E-C examinations of the areas associated with the liner damage caused by wood left in the concrete are planned for the second ten-year intervallWE examinations since several examinations have shown no change in liner thickness. In light of the proposed TS Amendment to allow five-year extension of Type A test interval, please provide specific information to justify discontinuing the augmented examination of suspect liner area(s) during the second ten-year IWE interval.

Dominion Response North Anna Unit 2 also performed an (UT-thickness and visual VT-1) augmented examination (Category E-C) on the liner at the concrete floor interface described in the report provided in NRC Question 4. The examination was performed in the general area of the original low point in an accessible region near the liner to floor interface to observe any possible general degradation.

The discontinuance of the Category E-C examinations was based upon ASME Section XI, 2001 Edition through the 2003 Addenda (2nd Interval Code of reference),

IWE-2420(c), which states:

"When the reexaminations required by IWE-2420(b) reveal that the flaws or areas of degradation remain essentially unchanged for the next inspection period, these areas no longer require augmented examination in accordance with Table IWE 2500-1, Examination Category E-C." - Note: The code Page 6 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval changed in the 1998 Edition "to unchanged for the next inspection period." It previously required no change in three consecutive periods.

The original conditions were discovered during the fall 1999 refueling outage (period 1).

Category E-C examinations for each location were performed subsequently on the following dates:

• VT 03/12/01 (period 1),05/18/04 (period 2), and 03/20/07 (period 3)

• UT- thickness - 03/16 and19/01 (period 1), 10/11/05 (period 2), and 03/22/07 (period 3)

No evidence of continued degradation has been observed at any of the locations as evidenced by the examinations performed, and Category E-C examinations have been discontinued at these locations based upon IWE-2430(c). No other Category E-C examinations have been planned.

NRC Question 6 Please provide a summary of any degradation identified during past inspection of the containment moisture barrier (e.g., between liner and concrete floor)? If any, please describe the condition, corrective actions, and additional monitoring program.

Dominion Response The liner is installed directly on top of the 10' thick base mat and the 2' 6" containment floor slab pours are poured directly on top of the liner. There are no moisture barriers around the perimeter of containment at the liner to floor interface. Polysulfide sealant is used for "water stops" between the containment floor slab pours to prevent moisture from getting between the slab pours and underneath the floor. The containment floor slabs are tight against the liner and sloped towards the center of containment. No "moisture barrier" is used between the liner and containment floor at the perimeter either above or below the containment floor surface. The NAPS Unit 2 containment design does not include a moisture barrier at examination area C-D as indicated on ASME XI Fig. IWE-2500-1.

In March 1999 during a general visual examination of the containment liner, relevant indications (minor rust at the floor to liner interface) were observed between columns 11 and 13. Four areas at the interface varying from 4 inches to 24 inches were excavated by chipping concrete away from the liner floor. In the excavated areas, the rust on the liner was not thick or tightly adhered. Wall thickness measurements were made in a 2 x 2 inch grid pattern along the excavations and the nominal 0.385" liner thickness varied from 0.365" to 0.400" indicating that little wall loss had occurred.

Page 7 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Also in March 1999, one location 210" from column 6 about 1/4" wide by 1" long exhibited a wall thickness as low as 0.282 inches but it was visually evident that there was little or no wall loss on the inside of the liner. This indication was attributed to localized thinning on the outside of the liner such as may have been caused by a gouge during erection. This localized low area was evaluated and determined to be acceptable. VT-1 examinations were completed on this area in March 2001, May 2004 and March 2007 and UT examinations were completed in March 2001, October 2005 and March 2007. No evidence of further degradation was noted in this area.

NRC Question 7 Relative to the results of 1999 ILRT included in Section 4.2 of Attachment 1 to the TS amendment request, there appears to be a typographical error in the total value of.

Please review and discuss. Also, provide the actual as-left leakage for the last three Type A tests.

Dominion Response The "total leakage" value for the October 1999 test was incorrectly stated in Section 4.2.

The correct results for the October 1999 test are provided below.

A design leakage criterion for the North Anna Unit 1 and 2 containment structures is 0.1 wt. %/24 hours or 1.0 La which is 304.4 seth. 10 CFR 50 Appendix J testing criteria for Type B & C testing are 0.6 La or 182.6 scfh and Type A test criteria is 0.75 La or 228.3 scfh. The following provides the as-left leakage values for the last three Type A tests:

Unit 2 Type A Test History April 1989 October 1990 October 1999 Measured Leakage 0.24 La 0.20 La 0.450 La UCL Margin 0.03 La 0.03 La 0.004 La Non-vented Penalties 0.040 La Totals "As Left" 0.27 La 0.23 La 0.494 La Leakage Savings 0.090 La Totals "As Found" 0.584 La NRC Question 8 As summarized in Section 4.2 of Attachment 1 to the TS amendment request, the 1999 ILRT as-found leakage was more than twice the value of 1990 ILRT results. Please provide further information relative to the potential root cause for this increase. Also, Page 8 of 26

Serial No. OB-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval provide the Type B and Type C test results and their comparison with the allowable leakage rate specified in the plant Technical Specifications.

Dominion Response Many factors may affect the results of a Type A test.

• The fundamental approach to testing has changed since 1995. Prior tests extensively drained and vented systems. Since Option B, the containment is bottled up and the intent is to measure leakage from the structure, not from leakage paths that are already included in the LLRT program.

• Integrated leakage rates are not trendable since there are many variations as follows in conducting the test and analyzing the data. In general, the longer the test, the lower the final reported containment leakage rate. The length of stabilization period can affect the final reported containment leakage rate.

Older tests tended to use longer stabilization times and thus may report lower containment leakage rate.

• Typically, containment leakage rates start near or above the TS limit and slowly decrease over time. To arrive at the final true leakage rate may require conducting the test for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or longer. The BN-TOP-1 total time uses a 97.5% upper confidence limit versus 95% for mass point. Thus, tests conducted with total time data analysis tend to report higher containment leakage rates.

The following are some specific examples of the variables that can occur from test to test and cause variations in data points.

ILRT Comparison Data For Length Of Time Required For Test Completion.

Unit 2 1989 Unit 1 1993 Unit 2 1999 Unit 1 2007 Pressurization 11.5 hr 11.8 hr 11.3 hr 8.5 hr Stabilization 13.2 hr 5.2 hr 5.35 hr 5.0 hr Test Period 24 hr 34.0 hr 8.15 hr 8.0 hr Verification 5.75 hr 4.35 hr 5.63 hr 4.0 hr Depressurization 14 hr 16.0 hr 7.8 hr 5.9 hr Totals 69.2 hr 71.8 hr 38.3 hr 33.5 hr Page 9 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval As requested, the following provide the Unit 2 October 1999 Type B & C Leak Rate Test History:

As-Found Min Path As-Left Max Path As-Left Min Path Piping Penetrations 3.825 scfh 15.225 scfh 1.52 scfh Personnel Air Lock 5 scfh 5scfh 2.5 scfh Emergency Escape Air Lock 3.5 scfh 4.5 scfh 2.25 scfh Electrical Penetrations 0.356 scfh 0.712 scfh 0.356 scfh Equipment Hatch 0.125 scfh o scfh o scfh Fuel Transfer Tube o scfh Oscfh o scfh Total Local Leak Rate 12.806 scfh 25.437 scfh 6.626 scfh The instrument error associated with this testing was: +/- 0.0921 scfh NRC Question 9 In Section 4.6 of Attachment 1 to the TS amendment request, it is stated that in the second five-year IWL examination of North Anna Unit 2 containment structure (completed in August of 2007) several pieces of embedded material were identified.

Please discuss the type and the extent of concrete repair, and if there was any liner damage associated with this condition. Furthermore, please discuss if there has been a complete direct inspection of the North Anna Unit 2 containment structure.

Dominion Response The Unit 2 Containment Concrete IWL inspections were performed locally with the use of a crane and man basket for approximately 80 percent of the containment and remotely for the remaining 20 percent due to safety concerns around the safety valve discharge stacks. The inspections were completed in August 2007. Nine locations were found on the Unit 2 Containment that were suspect and require excavation to determine the extent of condition. Six were on the dome and three were on the shell.

To date, five locations, three on the shell and two on the dome, have been excavated leaving four additional locations to excavate. Two locations excavated are below the face of reinforcement with small diameter bars exposed and will require a Code repair.

The condition, though requiring repair, is not considered significant nor does it affect containment integrity. The other three locations excavated are not deep enough to be considered code repairs. The maximum depth of the five excavations is 6" deep in small areas and as such do not jeopardize the structural integrity of the containment.

The remaining four locations to be excavated are not expected to be any deeper than those already excavated. Consequently, the repair can be performed when support (personnel and crane) and environmental conditions are more optimal. These repairs are currently scheduled for repair in the summer of 2008.

Page 10 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval As all excavations to date are relatively shallow with respect to the thickness of the concrete containment, no liner damage has occurred and none is expected following the completion of the remaining four excavations. Concrete repair of the excavations found to extend beyond the face of the reinforcement will be controlled under an lSI Repair/Replacement Plan. Other conditions corrected will be treated as maintenance (non-lSI) activities. Essentially both types of repairs will be the same as far as the concrete is concerned. The excavations will be prepared, cleaned, pre-soaked, grouted and properly cured.

NRC Question 10 If bellows are used on penetrations through containment pressure-retaining boundaries at North Anna Unit 2, please provide information on their location, inspection, testing and operating experience with regard to detection of leakage through the penetration bellows.

Dominion Response The single fuel transfer tube for each of the two North Anna containment structures are the only penetrations that utilize a bellows arrangement to establish seals between the containment liner, transfer cavity, spent fuel pool, and the penetration itself. Pressure test channels are installed on the weld interface between the penetration piping and the containment liner and were used to verify weld quality during initial construction. There are no other test devices installed on the penetration piping and bellows. Therefore, the ability to perform local leak rate testing is not available. Penetration integrity is verified during the performance of the Integrated Leakage Rate Test (Type A). North Anna has no record of bellows leakage. Visual inspection is impossible because two of the three bellows are enclosed in sleeves in the fuel building and between the fuel and containment buildings. The third bellows is located between the containment and the fuel transfer canal, which is a three foot opening, covered by permanent shielding.

NRC Question 11 Please provide an overview of the containment liner coating inspection program at North Anna Unit 2 including inspection intervals, findings and corrective actions identified during recent inspections.

Dominion Response Engineering visually inspects the accessible areas of the containment liner coating each refueling outage looking for indications of coating damage. Indications of coating damage include cracking, peeling, wear, mechanical damage, and blisters. The inspection takes place as early as reasonably possible, usually within the first few days Page 11 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval of the outage. Coating defects, along with locations, are recorded, and Engineering determines which areas require repair. A Condition Report is generated for the inspection results. Repairs are generally completed during the same outage, with blisters receiving the highest priority.

Mechanical damage to coating is typically caused from the impact of transient material (e.g., scaffolding) as workers move the materials to the desired location. Whenever the liner is exposed and repair is needed, the area is scheduled to be recoated.

If identified repair areas can not be completed during the current outage due to schedule constraints or inaccessibility, an Engineering Review is conducted, the repairs are re-scheduled for next refueling outage, and a Condition Report is written.

The three most recent inspections of the North Anna Unit 2 containment liner coating (May 2004, October 2005 and March 2007) yielded indications of mechanical damage, coating delamination, and several blisters. All identified blisters were investigated and excavated the same outage as they were discovered. When delamination is discovered, any adjacent loose coating was removed.

NRC Question 12 In Section 4.6 of Attachment 1 to the TS amendment request, the following is stated:

The second ten-year interval IWE program for North Anna meets the requirements of the 2001 Edition through the 2003 Addenda of ASME Section XI. Categories E D and E-G are no longer part of the code. The relief requests above are not needed for the second ten-year interval since examination of seals and gaskets, and bolt torque or tension tests are no longer addressed by ASME Section XI. As such, the extension request will no longer impact the ASME Section XI program upon second interval start for each unit. Given the short time period remaining in the first ten-year IWE lSI interval for the North Anna units, and the Type Band C tests performed during the first ten-year IWE lSI interval, the Appendix J, Type A extension is seen as having a negligible impact."

Please provide clarification for the following:

a. The TS Amendment request submitted in Dominion letter dated December 5, 2007 is for North Anna Unit 2. It is not clear to the NRC staff why both units are being discussed in the above paragraph.

b. Please discuss the examination methodes) in North Anna Unit 2 to ensure leak tight integrity of those penetrations with seals and gaskets, and bolted connections.

c. Please clarify the last sentence of the subject paragraph (Given the short time period remaining *).

Page 12 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Dominion Response to 12a The second ten year IWE programs are identical for both North Anna Unit 1 and 2. The introductory sentence in the paragraph included a discussion of both units. The.

extension request is for Unit 2 only.

Dominion Response to 12b Category E-D (seals, gaskets, and moisture barriers) examinations were alternatively addressed by request RR-IWE2 approved by NRC letter dated April 21, 1999 (first ten-year interval). The alternative addressed Item Nos. E5.10 (seals) and E5.20 (gaskets).

North Anna Unit 2 has no Item No. E5.30 (moisture barriers) items. The alternative basis takes credit for the Appendix J, Type B test to adequately address the integrity of the seals and gaskets. The Appendix J, Type B test remains unaffected by the proposed Appendix J, Type A test frequency extension and continues to ensure the integrity of the seals and gaskets.

Category E-G (pressure retaining bolting) examinations were alternatively addressed by request RR-IWE5 approved by NRC letter dated April 21, 1999 (first ten-year interval).

Item No. E8.10 was not addressed by the alternative requirement and the required visual VT-1 examinations have been performed in accordance with the code. Item No.

E8.20 required a bolt torque or tension test and was the subject of the alternative request. The acceptability of the alternative request was based upon the Appendix J, Type B test which indirectly proved the adequacy of the bolt torque or tension by maintaining acceptable leak rates. The Appendix J, Type B test remains unaffected by the proposed Appendix J, Type A frequency extension. The proposed alternatives, the visual VT-1 examinations and the acceptable performance of Appendix J, Type B tests continue to ensure bolting integrity.

All testing is performed using the "Make-up" method and evaluated against station established administrative limits. If any of the limits are exceeded, then an engineering evaluation is performed and repairs completed if necessary.

• Equipment hatch, escape air lock, and interface between the air lock and hatch - The escape air lock is pressurized to Pa which simultaneously tests door seals, actuation rod penetrations, electrical penetrations, and port holes. The equipment hatch and interface are equipped with a double o-ring seal and the test pressure is applied between the two o-rings.

• The fuel transfer tube is sealed inside the containment building with a blind flange, equipped with a double o-ring seal. Test pressure is applied between the two o-rings.

• The personnel air lock is pressurized to Pa which simultaneously tests door seals, actuation rod penetrations, electrical penetrations, and port holes.

Page 13 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval

• All electrical penetrations are of the Conax design, utilizing a double o-ring to seal the flange and double compression seals for the feed-throughs. North Anna maintains approximately 20 psi of helium pressure on the seals at all times. These pressures are monitored on a monthly basis and recharged if low, and Type Bleak tested if zero.

Dominion Response to 12c The remaining examinations (visual, VT-3) for North Anna Unit 2 are associated with wetted surfaces of submerged areas (Item No. E1.12 Category E-A, ASME 2001 Edition through the 2003 Addenda). These examinations are scheduled for completion by the end of the fall 2008 refueling outage.

The Type Band C testing will continue during the extension in accordance with NEI 94-01, Rev.1 ensuring the integrity of the penetrations.

Page 14 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval TABLE TYPE BAND C PENETRATIONS TEST SCHEDULE DURING THE 5-YEAR EXTENSION Page 15 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Electrical Penetrations History & Testing required (outage):

UNIT 2 ELECTRICAL PENETRATION EVALUATION ELECTRICAL Fall ~pring Fall ~pring Fall FOR NORTH ANNA ILRT FIVE YEAR EXTENSION PENETRATION NO. 2008 2010 2011 2013 2014 1A O-rino NT NT NT NT T 1A Canister F2 F3 NT NT NT 18 O-rina NT NT NT NT T Testing Required Codes:

18 Canister M, T NT NT NT NT T - TYPE B SCHEDULE 1C O-rino NT NT NT NT T F - FAILURE 1C Canister M, T NT NT NT NT M - MAINTENENCE 10 O-rino NT NT NT NT T D - DESIGN CHANGE 10 Canister M, T NT NT NT NT NT - NOT TESTED DURING OUTAGE 1E Ovrinq NT NT NT NT T F(n) - Test following previous failure 1E Canister NT NT NT NT T NORMAL FREQUENCY EVERY 6TH OUTAGE 2A NT NT NT NT T 28 NT NT NT NT T 2C NT NT NT NT T 20 NT NT NT NT T 2E NT NT NT NT T 3A NT NT NT NT T 38 NT NT NT NT T 3C NT NT NT NT T 30 NT NT NT NT T 3E NT NT NT NT T 4A NT NT NT NT T 48 F1 F2 F3 NT NT 4C NT NT NT NT T 40 NT NT NT NT T 4E NT NT NT NT T 5A NT NT NT NT NT 58 NT NT NT NT NT Page 16 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval History & Testing required (outage):

UNIT 2 ELECTRICAL PENETRATION EVALUATION ELECTRICAL Fall Ispring Fall Ispring Fall FOR NORTH ANNA ILRT FIVE YEAR EXTENSION PENETRATION NO. 2008 2010 2011 2013 2014 5C NT NT NT NT NT 50 NT NT NT NT NT 5E NT NT NT NT NT Testing Required Codes:

6A NT NT NT NT NT T- TYPE BSCHEDULE 68 NT NT NT NT NT F- FAILURE 6C NT NT NT NT NT M- MAINTENENCE 60 F1 F2 F3 NT NT D- DESIGN CHANGE 6E NT NT NT NT NT NT - NOT TESTED DURING OUTAGE 7A NT NT NT NT NT F(n) - Test following previous failure 78 NT NT NT NT NT NORMAL FREQUENCY EVERY 6TH OUTAGE 7C NT NT NT NT NT 70 NT NT NT NT NT 7E NT NT NT NT NT 8A NT NT NT NT NT 88 NT NT NT NT NT 8C NT NT NT NT NT 80 NT NT NT NT NT 8E NT NT NT NT NT 9A T NT NT NT NT 9B T NT NT NT NT 9C T NT NT NT NT 90 T NT NT NT NT 9E T NT NT NT NT 10A T NT NT NT NT 10B T NT NT NT NT 10C T NT NT NT NT 100 T NT NT NT NT 10E T NT NT NT NT 11A T NT NT NT NT Page 17 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval History & Testing required (outage):

UNIT 2 ELECTRICAL PENETRATION EVALUATION ELECTRICAL Fall 1:;pring Fall ~pring Fall FOR NORTH ANNA ILRT FIVE YEAR EXTENSION PENETRATION NO. 2008 2010 2011 2013 2014 118 T NT NT NT NT 11C T NT NT NT NT 110 T NT NT NT NT 11 E T NT NT NT NT Testing Required Codes:

12A T NT NT NT NT T - TYPE B SCHEDULE 128 T NT NT NT NT F - FAILURE 12C T NT NT NT NT M - MAINTENENCE 120 T NT NT NT NT D - DESIGN CHANGE 12E T NT NT NT NT NT - NOT TESTED DURING OUTAGE 13A NT T NT NT NT F(n) - Test following previous failure 138 NT T NT NT NT NORMAL FREQUENCY EVERY 6TH OUTAGE 13C NT T NT NT NT 130 NT T NT NT NT 13E NT T NT NT NT 14A NT T NT NT NT 148 NT T NT NT NT 14C NT T NT NT NT 140 NT T NT NT NT 14E NT T NT NT NT 15A NT T NT NT NT 158 NT T NT NT NT 15C NT T NT NT NT 150 NT T NT NT NT 15E NT T NT NT NT 16A NT T NT NT NT 168 NT T NT NT NT 16C NT NT NT F3 NT 160 NT T NT NT NT 16E NT T NT NT NT Page 18 of 26

Serial No. OB-0092A Docket No. 50-339 Request forAdditional Information One-Time Five-Year Extension to Type A TestInterval History & Testing required (outage):

UNIT 2 ELECTRICAL PENETRATION EVALUATION ELECTRICAL Fall bpring Fall ~pring Fall FOR NORTH ANNA ILRT FIVE YEAR EXTENSION PENETRATION NO. 2008 2010 2011 2013 2014 17A NT NT T NT NT 178 NT NT T NT NT 17C NT NT T NT NT 170 NT NT T NT NT 17E NT NT T NT NT Testing Required Codes:

18A NT NT T NT NT T - TYPE B SCHEDULE 188 NT NT T NT NT F - FAILURE 18C NT NT T NT NT M - MAINTENENCE 180 NT NT T NT NT D - DESIGN CHANGE 18E NT NT T NT NT NT - NOT TESTED DURING OUTAGE 19A NT NT T NT NT F(n) - Test following previous failure 198 NT NT T NT NT Testing Required Codes:

19C NT NT T NT NT NORMAL FREQUENCY EVERY 6TH OUTAGE 190 NT NT T NT NT 19E NT NT T NT NT 20A NT NT T NT NT 208 NT NT T NT NT 20C NT NT T NT NT 200 NT NT T NT NT 20E NT NT T NT NT 21A NT NT NT T NT 218 NT NT NT T NT 21C NT NT NT T NT 210 NT NT NT T NT 21E NT NT NT T NT 22A F3 NT NT NT NT 228 NT NT NT T NT 22C F3 NT NT NT NT 220 NT NT NT T NT Page 19 of 26

Serial No.08-0092A Docket No.50-339 Request for Additional Information One-Time Five-Year Extension to TypeA Test Interval History & Testing required (outage):

UNIT 2 ELECTRICAL PENETRATION EVALUATION ELECTRICAL Fall ~pring Fall ~pring Fall FOR NORTH ANNA ILRT FIVE YEAR EXTENSION PENETRATION 2008 2010 2011 2013 2014 NO.

22E NT NT NT T NT 23A NT NT NT T NT 238 NT NT NT T NT 23C NT NT NT T NT 23D NT NT NT T NT Testing Required Codes:

23E NT NT NT T NT T - TYPE B SCHEDULE 24A NT NT NT T NT F - FAILURE 24A M,T NT NT NT NT M - MAINTENENCE 248 NT NT NT T NT D - DESIGN CHANGE 248 M, T NT NT NT NT NT - NOT TESTED DURING OUTAGE 24C NT NT NT T NT F(n) - Test following previous failure 24D NT NT NT T NT Testing Required Codes:

24E NT NT NT T NT NORMAL FREQUENCY EVERY 6TH OUTAGE 24E NT NT NT T NT F1 NT NT NT T NT Page 20 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Mechanical Penetrations Required Testing UNIT 2 MECHANICAL PENETRATION PENETRATION EVALUATION VALVE Fall Spring Fall Spring Fall FUNCTION PEN FOR NORTH ANNA ILRT NO. FIVE YEAR EXTENSION NUMBER 2008 2010 2011 2013 2014 March 19, 2008 CC FM B RHR HX 1 2-CC- TV-203B NT NT C NT NT NORMAL FREQUENCY EVERY3RD CC TO A RHR HX 2 2-CC-194 C NT NT C NT OUTAGE Testing Required Codes:

CC TO B RHR HX 4 2-CC-199 NT NT C NT NT C - TYPE C SCHEDULE CC FROM A RHR HX 5 2-CC-TV-203A NT NT C NT NT (C) - EVERYOUTAGE CC FROM RCP 8 2-CC-TV-201 8 NT C NT NT C THERMAL BARRIER M - MAINTENANCE 2-CC-TV-201A NT C NT NT C F - FAILURE CC TO C CARF 9 2-CC-302 C NT NT C NT D - DESIGN CHANGE CC TO B CARF 10 2-CC-289 C NT NT C NT OR - REQUESTED BY OPS CC TO A CARF 11 2-CC-276 C NT NT C NT NT - NOT TESTED CC FROM "8" 12 2-CC-TV-205B C NT NT C NT F(n) - Test following previous failure CARF 2-CC-TV-200B M NT NT C NT CC FROM "C" 13 2-CC-TV-205C NT C NT NT C CARF 2-CC-TV-200C NT C NT NT C Acronyms CC FROM "A" 14 2-CC-TV-205A C NT NT C NT CC - Component Cooling Water CARF 2-CC- TV-200A M,T NT NT C NT RHR - Residual Heat Removal CC TO C RCP 16 2-CC-152 NT NT C NT NT RCP - Reactor Coolant Pump CARF - Cont Air Recirculation 2-CC- TV-204C NT NT C NT NT Fan RWST - Refuel Water Storage CC TO B RCP 17 2-CC-115 NT NT C NT NT Tank 2-CC-TV-204B NT C NT NT C HC - Hydrogen Recombination CC TO A RCP 18 2-CC-78 C NT NT C NT PRT - Pressurizer Relief Tank 2-CC- TV-204A M NT NT C NT QS - Quench Spray System SEAL WATER FROM 19 2-CH-331 C NT NT C NT RS - Recirculation Spray System RCPs RSHX - Recirculation Spray Heat 2-CH-MOV-2380 M, T NT NT C NT Exchangers CV - Containment Vacuum 2-CH-MOV-2381 M,T NT NT C NT System ACCUMULATOR LM - Containment Leakage 20 2-SI-136 NT G NT NT G MAKEUP Monitoring System 2-SI-47 NT C NT NT C Page 21 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Required Testing UNIT 2 MECHANICAL PENETRATION PENETRATION EVALUATION VALVE Fall Spring Fall Spring Fall FUNCTION PEN FOR NORTH ANNA ILRT NO. FIVE YEAR EXTENSION NUMBER 2008 2010 2011 2013 2014 March 19, 2008 RHR TO RWST 24 2-RH-37 NT NT C NT NT NORMAL FREQUENCY EVERY 3RD 2-RH-38 NT NT C NT NT OUTAGE CC FROM A RCP 25 2-CC-TV-202F M,T NT NT C NT Testing Required Codes:

2-CC-TV-202E C NT NT C NT C - TYPE C SCHEDULE CC FROM C RCP 26 2-CC-TV-202B M, T NT NT C NT (C) - EVERYOUTAGE 2-CC-TV-202A C NT NT C NT M - MAINTENANCE CC FROM B RCP 27 2-CC-TV-202D M,T NT NT C NT F - FAILURE 2-CC-TV-202C C NT NT C NT D - DESIGN CHANGE OR . REQUESTED BY OPS LETDOWN 28 2-CH-TV-2204A M,T NT NT C NT 2-CH-TV-2204B C NT NT C NT F(n) - Test following previous failure HC SYSTEM 31 2-HC-15 F1 F2 NT NT C 2-HC-TV-205A NT NT C NT NT 2-HC-TV-205B NT NT C NT NT 2-HC-TV-201A NT NT C NT NT 2-HC-TV-201 B NT NT C NT NT WET LAYUP A SG 32 2-WT-437 NT C NT NT C 2-WT-446 NT C NT NT NC PRIMARY DRAIN 33 2-DG-TV-200B M,T NT NT C NT TRANSFER 2-DG-TV-200A C NT NT C (NT FIRE PROTECTION 34 2-FP-79 (C) (C) (C) (C) © 2-FP-81 (C) (C) (C) (C) (C)

SUMP DISCHARGE 38 2-DA-TV-200B (C) (C) (C) (C) (C) 2-DA-TV-200A (C) (C) (C) (C) (C)

A BLOWDOWN 39 2-BD-TV-200B (C) (C) (C) (C) (C) 2-BD-TV-200A (C) (C) (C) (C) (C)

C BLOWDOWN 40 2-BD-TV-200F (C) (C) (C) (C) (C) 2-BD-TV-200E (C) (C) (C) (C) (C)

B BLOWDOWN 41 2-BD-TV-200D (C) (C) (C) (C) (C)

Page 22 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Required Testing UNIT 2 MECHANICAL PENETRATION PENETRATION EVALUATION VALVE Fall 8pring Fall 8pring Fall FUNCTION PEN FOR NORTH ANNA ILRT NO. FIVE YEAR EXTENSION NUMBER 2008 2010 2011 2013 2014 March 19, 2008 B BLOWDOWN (cont.) 2-BD-TV-200C (C) (C) (C) (C) (C)

RD NORMAL FREQUENCY EVERY 3 SERVICE AIR 42 2-8A-123 NT NT C NT NT OUTAGE 2-8A-65 NT NT C NT NT AIR MONITOR 43 2-IA-428 M,T NT NT C NT Testing Required Codes:

2-RM-TV-200A C NT NT C NT C - TYPE C SCHEDULE AIR MONITOR 44 2-RM-TV-200C NT C NT NT C (C) - EVERY OUTAGE 2- RM-TV -200B NT C NT NT C M - MAINTENANCE PRIMARY GRADE 45 2-RC-162 C NT NT C NT WATER F - FAILURE 2-RC-TV-2519A C NT NT C NT D - DESIGN CHANGE INSTRUMENT AIR 47 2-IA-250 F1 F2 C NT NT OR - REQUESTED BY OPS 2-IA-TV-202A C NT NT C NT NT - NOT TESTED PRIMARY VENT 48 2-VG-TV-200B NT C NT NT C HEADER F(n) - Test following previous failure 2-VG-TV-200A NT C NT NT C N2 TO PRIMARY 50 2-81-HCV-2936 M, T NT NT C NT RELIEF TANK 2-81-TV-201 C NT NT C NT 53 2-81-132 F1 F2 NT NT C 2-81-TV-200 C NT NT C NT PRIMARY VENT POT 54 2-DA-7 NT NT C NT NT VENT 2-DA-9 NT NT C NT NT LEAKAGE 55D 2-LM-TV-200F NT NT C NT NT MONITORING 2-LM-TV-200E NT NT C NT NT PZR LIQUID 8PACE 56A 2-88-TV -200A C NT NT C NT 2-88-TV -200B M, T NT NT C NT HOT LEG 56B 2-88-TV -206A NT NT C NT NT 2-88-TV-206B NT NT C NT NT COLD LEG 56C 2-88-TV -202A NT C NT NT C 2-SS-TV-202B NT C NT NT C 8G BLOWDOWN 56D 2-88-TV-212A NT C NT NT C Page 23 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Required Testing UNIT 2 MECHANICAL PENETRATION PENETRATION EVALUATION VALVE Fall Spring Fall Spring Fall FUNCTION PEN FOR NORTH ANNA ILRT NO. FIVE YEAR EXTENSION NUMBER 2008 2010 2011 2013 2014 March 19,2008 SG BLOWDOWN (cont) 2-SS-TV-212B NT C NT NT C LEAKAGE MONIT 57A 2-LM-TV-200H NT NT C NT NT NORMAL FREQUENCY EVERY 3RD 2-LM-TV-200G NT NT C NT NT OUTAGE PRT GAS SPACE 57B 2-SS-TV-204A M,T NT NT C NT 2-SS-TV-204B C NT NT C NT Testing Required Codes:

PZR VAPOR SPACE 57C 2-SS-TV-201A M,T NT NT C NT C - TYPE C SCHEDULE 2-SS-TV-201 B M,T NT NT C NT (C) - EVERYOUTAGE OS PUMP B 63 2-0S-22 M, T NT NT C NT M - MAINTENANCE 2-0S-MOV-201 B C NT NT C NT F - FAILURE OS PUMP A 64 2-0S-11 M,T C NT NT C D - DESIGN CHANGE 2-0S-MOV-201 A C C NT NT C OR - REQUESTED BY OPS SW TO/ FROM 79 2-SW-MOV-203D NT NT C NT NT NT - NOT TESTED RSHX'S 80 2-SW-MOV-203C NT NT C NT NT F(n) - Test following previous failure RSHX'S 81 2-SW-MOV-203B M,T NT NT C NT RSHX'S 82 2-SW-MOV-203A M, T NT NT C NT RSHX'S 83 2-SW -MOV-204A C NT NT C NT RSHX'S 84 2-SW-MOV-204B M,T NT NT C NT RSHX'S 85 2-SW-MOV-204C NT NT C NT NT RSHX'S 86 2-SW-MOV-204D NT NT C NT NT AIR EJECTOR 89 2-VP-24 F2 NT NT C NT DISCHARGE TO CONTAINMENT 2-SV-TV-203 M,T NT NT C NT CONTAINMENT 90 2-HV-MOV-200C (C) (C) (C) (C) (C)

PURGE 2-HV-MOV-200D (C) (C) (C) (C) (C)

EXHAUST 2-HV-MOV-201 (C) (C) (C) (C) (C)

CONTAINMENT 91 2-HV-MOV-200A (C) (C) (C) (C) (C)

PURGE 2-HV-MOV-200B (C) (C) (C) (C) (C)

SUPPLY 2-HV-MOV-202 (C) (C) (C) (C) (C)

CV PUMP SUCTION 92 2-HC-TV-204A C NT NT C NT Page 24 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Required Testing UNIT 2 MECHANICAL PENETRATION PENETRATION EVALUATION VALVE Fall Spring Fall Spring Fall FUNCTION PEN FOR NORTH ANNA ILRT NO. FIVE YEAR EXTENSION NUMBER 2008 2010 2011 2013 2014 March 19,2008 CV PUMP SUCTION 2-CV-TV -250C M,T NT NT C NT (cont.)

NORMAL FREQUENCY EVERY3RD 2-HC-TV-204B C NT NT C NT OUTAGE 2-CV-TV-250D M,T NT NT C NT Testing Required Codes:

CV PUMP SUCTION 93 2-HC-TV-206A F1 F2 NT NT C C - TYPE C SCHEDULE 2-CV-TV-250A M,T NT NT C NT (C) - EVERY OUTAGE 2-HC-TV-206B C NT NT C NT M - MAINTENANCE 2-CV-TV-250B M, T NT NT C NT F - FAILURE CONTAINMENT 94 2-CV-TV-200 F1 F2 (C) (C) (C)

HOGGER D - DESIGN CHANGE 2-CV-4 F1 F2 (C) (C) (C)

OR - REQUESTED BY OPS RHR LIQUID 97A 2-SS-TV-203A C NT NT C NT NT - NOT TESTED 2-SS-TV-203B F2 NT NT C NT F(n) - Test following previous failure LEAKAGE 97B 2-LM-TV-200B NT NT C NT NT MONITORING 2-LM-TV -200A NT NT C NT NT PZR DEAD WT 97C 2-RC-143 NT NT C NT NT 2-RC-145 NT NT C NT NT HYDROGEN RECOMBINATION 98A 2-HC-TV-200A C NT NT C NT SYSTEM 2-HC-TV-200B C NT NT C NT HYDROGEN RECOMBINATION 98B 2-HC-TV-208A NT NT C NT NT SYSTEM 2-HC-TV-208B NT NT C NT NT WET LAYUP B SG 100 2-WT-438 C NT NT C NT 2-WT-447 C NT NT C NT REFUEL 103 2-RP-7 NT C NT NT C PURIFICATION 1-RP-84 NT C NT NT C REFUEL 104 2-RP-6 C NT NT C NT PURIFICATION 1-RP-50 C NT NT C NT LEAKAGE 105A 2-LM-TV-200D NT NT C NT NT MONITORING LEAKAGE 2-LM-TV-200C NT NT C NT NT MONITORING (cant)

Page 25 of 26

Serial No. 08-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval Required Testing UNIT 2 MECHANICAL PENETRATION PENETRATION EVALUATION VALVE Fall Spring Fall Spring Fall FUNCTION PEN FOR NORTH ANNA ILRT NO. FIVE YEAR EXTENSION NUMBER 2008 2010 2011 2013 2014 March 19, 2008 HYDROGEN RECOMBINATION 105B 2-HC-TV-202A C NT NT C NT SYSTEM NORMALFREQUENCYEVERY3~

2-HC-TV-202B C NT NT C NT OUTAGE LEAKAGE 105C 2-LM-TV-201 D NT NT C NT NT MONITORING 2-LM-TV -201 A NT NT C NT NT Testing Required Codes:

LEAKAGE 105D 2-LM-TV-201B NT NT C NT NT MONITORING C - TYPE C SCHEDULE 2-LM-TV -201 C NT NT C NT NT (C) - EVERY OUTAGE SAFETY INJECTION 106 2-SI- TV-2842 NT NT C NT NT TEST LINE M - MAINTENANCE 2-SI-TV-2859 NT NT C NT NT F - FAILURE WET LAYUP C SG 108 2-WT-439 NT NT C NT NT D - DESIGN CHANGE 2-WT-448 NT NT C NT NT OR - REQUESTED BY OPS HYDROGEN RECOMBINATION 109 2-HC-20 C NT NT C NT SYSTEM F(n) - Test following previous failure 2-HC-TV-203A C NT NT C NT 2-HC-TV-203B C NT NT C NT 2-HC-TV-207A C NT NT C NT 2-HC-TV-207B F2 NT NT C NT POST ACCIDENT 1110 2-DA-TV-203A F1 F2 NT NT C 2-DA-TV-203B C NT NT C NT INSTRUMENT AIR 112 2-1 A-TV-201 A NT NT C NT NT 2-1A-TV-201B NT NT C NT NT Page 26 of 26

Serial No. OB-0092A Docket No. 50-339 Request for Additional Information One-Time Five-Year Extension to Type A Test Interval ATTACHMENT NORTH ANNA UNIT 2'S INSERVICE INSPECTION

SUMMARY

REPORT FALL 1999 REFUELING OUTAGE JANUARY 3, 2000 CONTAINMENT INSERVICE INSPECTION

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 January 3, 2000 United States Nuclear Regulatory Commission Serial No.: 99-618 Attention: Document Control Desk NLOS/MM Washington, DC 20555-0001 Docket No.: 50-339 License No.: NPF-7 Gentlemen:

VIRGINIA ELECTRIC AND POWER COMPANY NORTH ANNA POWER STATION UNIT 2 INSERVICE INSPECTION

SUMMARY

REPORT FOR THE FALL 1999 REFUELING OUTAGE As set forth in the provisions of ASME Section XI, Paragraph IWA-6230, enclosed is the Inservice Inspection Summary Report for North Anna Power Station Unit 2 for the Fall 1999 refueling outage. This report provides a summary of the examinations performed during the outage for the third inservice inspection interval. In addition, the report summarizes the inspection activities associated with 10 CFR 50.55a(b)(ix)(E) and 10 CFR 50.55a(b)(x)(A).

In accordance with IWA-6220 of ASME Section XI, Attachment 1 includes a Form NIS-1, "Owner's Report for Inservice Inspections," an examination summary, and abstracts of examinations performed. Attachment 2 includes Forms NIS-2, "Owner's Report for Repairs or Replacements."

The entire report will be maintained on file at the corporate office. If you have any questions or require additional information, please contact us.

Very truly yours, L. N. Hartz Vice President - Nuclear Engineering and Services Attachments 1 of 5

Attachment 1 Page 27 of 30 Serial No.: 99-601 Docket No.: 50-339 Abstract of Examinations Containment Inservice Inspection I. The requirements of 10 CFR 50.55a(b)(ix)(E) state for Class CC applications, that the licensee shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. For each inaccessible area identified, the licensee shall provide the following in the 151 Summary Report required by IWA-6000:

1) A description of the type and estimated extent of degradation, and the conditions that led to the degradation; Discovery of a blister in the liner protective coating at about the 246 foot elevation near column 5 and subsequent removal of the blister revealed a corroded spot under the paint. Probing of the approximately ~ inch diameter corroded spot revealed a deep pit believed to be through wall. Subsequent pressure testing confirmed the hole to be through the liner. UT thickness measurements made in the vicinity of the hole on a 2 inch X 2 inch grid, revealed anomalous readings that were not indicative of the suspected corrosion mechanism and prompted the removal of a 5 inch X 7 inch piece of the liner roughly centered on the hole and another about 3 inch diameter piece of the liner a short distance from the hole. Examination of the removed pieces revealed, contrary to expectation, that corrosion had occurred from the inside of the liner to the outside. There had actually been extensive corrosion of the liner material in contact with the concrete. Examination of the exposed concrete surface revealed the presence of a piece of wood, subsequently determined to be a 4 inch X 4 inch timber, approximately 6 feet in length, which had been in contact with the liner at the location of the hole. The 4X4 was embedded in the concrete and appears to have been present since the initial concrete placement.

2) An evaluation of each area, and the result of the evaluation; The location and size of the 4X4 was determined by combining visual examinations, UT thickness measurements of liner degradation and mechanical probes. The concrete structure was assessed as being affected slightly. but retaining the required minimum design.

3) A description of necessary corrective actions; The 4X4 was removed and the concrete void was grouted.

II (a). The requirements of 10 CFR 50.55a(b)(x)(A) state for Class MC applications, that the licensee shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result 2 of 5

Attachment 1 Page 28 of 30 Serial No.: 99-601 Docket No.: 50-339 in degradation to such inaccessible areas. For each inaccessible area identified, the licensee shall provide the following in the lSI Summary Report required by IWA-6000:

1) A description of the type and estimated extent of degradation, and conditions that led to the degradation; Discovery of a blister in the liner protective coating at about the 246 foot elevation near column 5 and subsequent removal of the blister revealed a corroded spot under the paint. Probing of the approximately Y4 inch diameter corroded spot revealed a deep pit believed to be through wall. Subsequent pressure testing confirmed the hole to be through the liner. UT thickness measurements made in the vicinity ofthe hole on a 2 inch X 2 inch grid, revealed anomalous readings that were not indicative of the suspected corrosion mechanism and prompted the removal of a 5 inch X 7 inch piece of the liner roughly centered on the hole and another about 3 inch diameter piece of the liner a short distance from the hole. Examination of the removed pieces revealed.

contrary to expectation. that corrosion had occurred from the inside of the liner to the outside. There had actually been extensive corrosion of the liner material in contact with the concrete. Examination of the exposed concrete surface revealed the presence of a piece of wood. subsequently determined to be a 4 inch X 4 inch timber, approximately 6 feet in length, which had been in contact with the liner at the location of the hole. The 4X4 was embedded in the concrete and appears to have been present since the initial concrete placement.

Analysis of the removed steel indicates that the contact of the liner plate with the wood timber interfered with the normal tendency for concrete's alkalinity to inhibit corrosion of embedded steel. The occlusion of the surface at the point of contact between steel and timber created a point of active corrosion, undoubtedly influenced by the residual moisture in the wood. There is evidence that the influence of the wood was felt beyond the point of closest contact. Presumably this was because of the less than optimal concrete to steel interface that would have occurred due to the presence of the obstruction to effective consolidation of the concrete in the area caused by the wood.

2) An evaluation of each area. and the result of the evaluation; UT thickness readings were made on an extended area on either side of the hole location using a 1 inch X 1 inch inspection grid. The inspection revealed a pattern of lower than the constructed minimum (0.375 inch) thicknesses in a band about 18 inch high by about 8 foot long extending both directions from the hole. Based on an analyzed minimum acceptable wall thickness in the area of 0.250 inch, and to aid removal of the wood from the wall, sections of liner about 10 inches long and 3 inches high were removed along the band of low readings.

One additional section about 4 X 4 inch area with a measured wall thickness less than 0.250 inch was also removed.

3 of 5

Attachment 1 Page 29 of 30 Serial No.: 99-601 Docket No.: 50-339

3) A description of necessary corrective actions; All of the liner plate requiring replacement at elevation 246 feet and column 5 was replaced prior to restart. Some degraded plate, that is, liner exhibiting less than the constructed minimum 0.375 inch wall thickness but still thicker than the 0.250 inch minimum acceptable wall thickness, remains in the area. To confirm that the removal of the 4 X 4 has eliminated the corrosion mechanism, it was necessary to establish baseline thickness readings on the unremoved material and to monitor those areas for the next 3 lSI periods by UT performing thickness measurements.

II (b). The requirements of 10 CFR 50.55a(b)(x)(A) state for Class MC applications, the licensee shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. For each inaccessible area identified, the licensee shall provide the follOWing in the lSI Summary Report required by IWA-6000:

1) A description of the type and estimated extent of degradation and conditions I

that led to the degradation; During the Code required General Visual examination it was noted that there were a number of areas at the interface of the containment steel liner with the concrete floor where there was evidence of some apparent rust. The rust was apparently the result of atmospheric humidity or possibly surface moisture being in contact with the carbon steel over the years of operation.

2) An evaluation of each area, and the result of the evaluation; Initial assessment indicated the adVisability of removing some concrete in a sample of the questionable areas to more effectively evaluate the condition.

Four areas at the liner to floor interface varying in length from about 4 inches to about 24 inches were excavated in the concrete with a chipping hammer to an initial depth of about 1 inch and a width of about 1 inch. The excavated areas were cleaned of debris and visually examined. In all cases there was evidence of some rust bloom or stain on the steel surface below the level of the floor for a short distance. The rust was not thick or scale like, nor particularly tightly adherent. In two of the excavations the rust appeared to continue deeper than the initial 1 inch excavation and additional excavation was performed. In one of these areas the removal of about an additional 1 inch of concrete for a length of about 12 inches exposed uncorroded liner steel. In the about 4 inch long excavation the removal of about another 2 inches of concrete more than reached the limit of any corrosion.

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Attachment1 Page 30 of 30 Serial No.: 99-601 Docket No.: So-339 Wall thickness measurements were made in a grid pattern along the length of the excavations. Wall thicknesses of the constructed minimum 0.375 inch liner plate varied from about 0.365 inch to about 0.400 inch indicating the maximum wall loss that may have occurred is about 0.035 inch, which agrees well with the observation of little or no visible loss of metal from the liner.

There was one location in an excavated area located about 210 inches from column 6 towards column 7 and about % inch below the floor level that exhibited a wall thickness as thin as 0.282 inch. The spot was about 1 inch long and %

inch wide. Since it was visibly evident that there was little or no loss of wall on the inside of the liner, because the variation in thickness in the area was not consistent with a plate lamination, and based on the assessment by NDE personnel, it was concluded that the area probably represents a local thinning on the outside surface of the liner plate such as might have been caused by a gouge during erection. Analysis of the effect of the thinned area indicates that the structural and leak tight integrity of the liner is maintained.

The assessment of the four excavated areas reveals that there has been very little general loss' of liner wall thickness (about a maximum of 0.035 inch) in the approximately 18 years of operation of NAPS Unit 2 at the liner to floor interface.

Additionally, it is apparent that the depth of the corrosion process is minimal, extending a maximum of about 3 inches below the level of the floor. Based on the areas examined, there is no concern relative to the structural integrity or leak tightness of the liner. Consequently, it is concluded that based on a possible average corrosion rate less than 0.002 inch a year, continued operation of the unit while the rest of the identified liner to floor interface areas of concern remain unrepaired is acceptable because the liner will continue to be fUlly capable of performing its design function, i.e. preventing leakage of containment atmosphere to the environment.

3) A description of necessary corrective actions; The area with the indicated 0.282 wall thickness should be monitored for the next 3 lSI Periods to verify that no corrosion between the steel liner and containment wall is occurring by performing UT thickness measurements. Therefore repair of the concrete floor in the areas shall be postponed until such time as it has been demonstrated that the indication is not growing. The protective coatings on the liner have been repaired. It is necessary to reinspect the area through the paint to establish a baseline for future comparison. Finally, the excavation in the concrete floor has the potential to collect water, which might promote corrosion.

Normal outage walk downs should assure the area stays dry.

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