NL-09-0547, License Amendment Request to Revise Technical Specification (TS) Sections 5.5.9, Steam Generator (SG) Program and TS 5.6.10, Steam Generator Tube Inspection Report for Permanent Alternate Repair Criteria
| ML091470701 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 05/19/2009 |
| From: | Ajluni M Southern Nuclear Operating Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NL-09-0547 | |
| Download: ML091470701 (35) | |
Text
Southern Nuclear Operating Company, Inc.
Post Office Box 1295 Birmingham, Alabama 35201-1295 Tel 205.992.5000 May 19, 2009 Energy to Serve Your World'"
Docket Nos.: 50-424 NL-09-0547 50-425 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Vogtle Electric Generating Plant License Amendment Request to Revise Technical Specification (TS) Sections 5.5.9, "Steam Generator (SG) Program" and TS 5.6.10, "Steam Generator Tube Inspection Report" for Permanent Alternate Repair Criteria Ladies and Gentlemen:
Pursuant to.10 CFR 50.90, Southern Nuclear Operating Company (SNC) hereby requests an amendment to Facility Operating License Nos. NPF-68 and NPF-81 for Vogtle Electric Generating Plant (VEGP), Units 1 and 2, respectively. This amendment request proposes to permanently revise VEGP Technical Specification'(TS) 5.5.9, "Steam Generator (SG) Program," to exclude portions of the tube below the top of the steam generator tubesheet from periodic steam generator tube inspections. This permanent change is supported by Westinghouse Electric Company LLC, WCAP-17071-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)."
The SNC requests approval of the proposed license amendments by September 18, 2009 to support implementation during Vogtle Unit 1 fall refueling outage. The proposed changes will be implemented within 30 days of issuance of the amendment.
The NRC commitments contained in this letter are provided in Enclosure 4. If you have any questions, please advise.
Mr. M. J. Ajluni states he is Nuclear Licensing Manager of Southern Nuclear Operating Company, is authorized to execute this oath on behalf of Southern Nuclear Operating Company and to the best of his knowledge and belief, the facts set forth in this letter are true.
40o(
U. S. Nuclear Regulatory Commission NL-09-0547 Page 2 Respectfully submitted, SOUTHERN NUCLEAR OPERATING COMPANY,.
M. J. Ajiuni Manager, Nuclear Licensing " ... ,,,,
Sworn to and subscribedbefore me this day of ,2009.
Notary Pub ic 0 My commission expires: 2' o~i/- 'I-MJA/TAH/DAJ
Enclosures:
- 1. Basis for Proposed Change
- 2. Markup of Proposed Teclhnical Specification
- 3. Typed Pages for Technical Specification
- 4. List of Regulatory Commitments
- 5. Westinghouse Electric Company LLC WCAP-17071-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)" (Proprietary)
- 6. Westinghouse Electric Company LLC WCAP-1 7071-NP, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)" (Non-Proprietary)
- 7. Westinghouse Electric Company LLC LTR-CAW-09-2568, "Application for Withholding Proprietary Information from Public Disclosure" cc: Southern Nuclear Operatinq Company Mr. J. T. Gasser, Executive Vice President Mr. T. E. Tynan, Vice President - Vogtle Ms. P. M. Marino, Vice President - Engineering RType: CVC7000 U. S. Nuclear Regulatory Commission Mr. L. A. Reyes, Regional Administrator Ms. D. Wright, NRR Project Manager - Vogtle Mr. M. Cain, Senior Resident Inspector - Vogtle State of Georgia Mr. N. Holcomb, Commissioner - Department of Natural Resources
Vogtle Electric Generating Plant Units 1 and 2 License Amendment Request to Revise Technical Specification (TS)
Sections 5.5.9, "Steam Generator (SG) Program" and TS 5.6.10, "Steam Generator Tube Inspection Report" for Permanent Alternate Repair Criteria Enclosure 1 Basis for Proposed Change
Vogtle Electric Generating Plant Units 1 and 2 License Amendment Request to Revise Technical Specification (TS)
Sections 5.5.9, "Steam Generator (SG) Program" and TS 5.6.10, "Steam Generator Tube Inspection Report" for Permanent Alternate Repair Criteria Enclosure 1 Basis for Proposed Change Table of Contents 1.0 Summary Description 2.0 Detailed Description 3.0 Background 4.0 Technical Evaluation 5.0 Regulatory Evaluation 5.1 Applicable Regulatory Requirements / Criteria 5.2 No Significant Hazards Consideration 5.3 Conclusion 6.0 Environmental Considerations 7.0 References El-1
Enclosure 1 Basis for Proposed Change 1.0 Summary Description Southern Nuclear Operating Company (SNC) proposes to revise the Vogtle Electric Generating Plant (VEGP) Technical Specifications (TS) 5.5.9, "Steam Generator (SG) Program," to exclude portions of the steam generator tube below the top of the steam generator tubesheet from periodic tube inspections. Application of the supporting structural analysis and leakage evaluation results to exclude portions of the tubes from inspection and repair of tube indications is interpreted to constitute a redefinition of the primary-to-secondary pressure boundary. The proposed changes to the TS are based on the supporting structural analysis and leakage evaluation contained in Westinghouse Electric Company, LLC WCAP-1 7071 -P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)", May 1, 2009 [Reference 5]. WCAP 17071-P recommends the 95/50 H* value of 11.2 inches; however, SNC has chosen to use an H* value of 13.1 inches for additional conservatism. This more conservative value was discussed between the NRC staff and industry representative on April 24, 2009 and May 1, 2009.
The NRC previously issued the following amendments revising steam generator tube inspection requirements:
" Amendment Numbers 138 and 117 (Units 1 and 2, respectively) (Reference 1) to exclude degradation found in the portion of the tubes below 17 inches from the top of the hot leg tubesheet from the requirement to plug for Unit 2 Refueling Outage 11 and the subsequent operating cycle.
" Amendments 146 and 126 (Units 1 and 2, respectively) (Reference 2) to exclude the portion of the tubes below 17 inches from the top of the hot leg tubesheet from the requirement to plug for Unit 1 Refueling Outage 13 and Unit 2 Refueling Outage 12 and the subsequent operating cycles.
- Amendment Numbers 150 and 130 (Units 1 and 2, respectively) (Reference 3) which approved an interim alternate repair criteria for Unit 1 Refueling Outage 14 and the subsequent operating cycle that requires full-length inspection of the tubes within the tubesheet but does not require plugging tubes if any circumferential cracking observed in the region greater than 17 inches from the top of the tubesheet is less than a value sufficient to permit the remaining circumferential ligament to transmit the limiting axial loads.
- Amendment Numbers 152 and 133 (Units 1 and 2, respectively) (Reference 4) applied the criteria of Amendments 150 and 130 to Unit 2 Refueling Outage 12 and the subsequent operating cycle.
Amendment Numbers 150 and 152 (Unit1) and 130 and 133 (Unit 2) are only applicable for Refueling Outages 14 (Unit 1) and 13 (Unit 2) and the subsequent operating cycles.
Approval of this amendment application is requested by September 18, 2009 to support VEGP 1 Refueling Outage 15 (fall 2009), since the existing one-cycle amendment expires at the end of the current operating cycle.
2.0 Detailed Description Proposed Changes to Current TS El1-2
Enclosure 1 Basis for Proposed Change TS 5.5.9.c. currently states:
- c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.
The following alternate tube repair criteria shall be applied as an alternative to the 40% depth based criteria:
- 1. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.
For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged upon detection.
- 2. For Unit 1 during Refueling Outage 13 and the subsequent operating cycle, and for Unit 2 during Refueling Outage 12 and the subsequent operating cycle, degradation identified in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.
For Unit 1 during Refueling Outage 13 and the subsequent operating cycle, and for Unit 2 during Refueling Outage 12 and the subsequent operating cycle, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the hot leg tubesheet shall be plugged upon detection.
- 3. For Unit 1 during Refueling Outage 14 and the subsequent operating cycle and for Unit 2 during Refueling Outage 13 and the subsequent operating cycle, tubes with flaws having a circumferential component less than or equal to 203 degrees found in the portion of the tube below 17 inches from the top of the tubesheet and above 1 inch from the bottom of the tubesheet do not require plugging. Tubes with flaws having a circumferential component greater than 203 degrees found in the portion of the tube below 17 inches from the top of the tubesheet and above 1 inch from the bottom of the tubesheet shall be removed from service.
Tubes with service-induced flaws located within the region from the top of the tubesheet to 17 inches below the top of the tubesheet shall be removed from service. Tubes with service-induced axial cracks found in the portion of the tube below 17 inches from the top of the tubesheet do not require plugging.
When more than one flaw with circumferential components is found in the portion of the tube below 17 inches from the top of the tubesheet and above 1 inch from the bottom of the tubesheet with the total of the circumferential components greater than 203 degrees and an axial El -3
Enclosure 1 Basis for Proposed Change separation distance of less than 1 inch, then the tube shall be removed from service. When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.
When one or more flaws with circumferential components are found in the portion of the tube within 1 inch from the bottom of the tubesheet, and the total of the circumferential components found in the tube exceeds 94 degrees, then the tube shall be removed from service.
When one or more flaws with circumferential components are found in the portion of the tube within 1 inch from the bottom of the tubesheet, and within 1 inch axial separation distance of a flaw above 1 inch from the bottom of the tubesheet, and the total of the circumferential components found in the tube exceeds 94 degrees, then the tube shall be removed from service. When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.
This section would be revised as follows, as noted in italic type:
- c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.
The following alternate tube repair criteria shall be applied as an alternative to the 40% depth based criteria:
Tubes with service-inducedflaws located greaterthan 13.1 inches below the top of the tubesheet do not requireplugging. Tubes with service-inducedflaws located in the portion of the tube from the top of the tubesheet to 13.1 inches below the top of the tubesheet shall be plugged upon detection.
TS 5.5.9.d currently states:
- d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. For Unit 1 during Refueling Outage 13 and the subsequent operating cycle, and for Unit 2 during Refueling Outage 12 and the subsequent operating cycle, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. The tube-to-tubesheet weld is not part of the tube.
In addition to meeting the requirements of d.1, d.2, and d.3 below, the El -4
Enclosure 1 Basis for Proposed Change inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.
- 2. Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.
- 3. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic nondestructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.
This section would be revised as follows, as noted in italic type:
- d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present from 13.1 inches below the top of tubesheet on the hot leg side to 13.1 inches below the top of the tubesheet on the cold leg side, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.
- 2. Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period El -5
Enclosure 1 Basis for Proposed Change shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.
- 3. If crack indications are found from 13.1 inches below the top of tubesheet on the hot leg side to 13.1 inches below the top of the tubesheet on the cold leg side, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic nondestructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.
TS 5.6.10 h., 5.6.10 i., and 5.6.10 j. currently state:
- h. Following completion of a Unit 1 inspection performed in Refueling Outage 14 (and any inspections performed in the subsequent operating cycle) and following completion of a Unit 2 inspection performed in Refueling Outage 13 (and any inspections performed in the subsequent operating cycle), the number of indications and location, size, orientation, whether initiated on primary or secondary side for each service-induced flaw within the thickness of the tubesheet, and the total of the circumferential components and any circumferential overlap below 17 inches from the top of the tubesheet as determined in accordance with TS 5.5.9.c.3; Following completion of a Unit 1 inspection performed in Refueling Outage 14 (and any inspections performed in the subsequent operating cycle) and following completion of a Unit 2 inspection performed in Refueling Outage 13 (and any inspections performed in the subsequent operating cycle), the primary to secondary LEAKAGE rate observed in each SG (if it is not practical'to assign leakage to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report; and
- j. Following completion of a Unit 1 inspection performed in Refueling Outage 14 (and any inspections performed in the subsequent operating cycle) and following completion of a Unit 2 inspection performed in Refueling Outage 13 (and any inspections performed in the subsequent operating cycle), the calculated accident leakage rate from the portion of the tube below 17 inches from the top of the tubesheet for the most limiting accident in the most limiting SG.
E1-6
Enclosure 1 Basis for Proposed Change TS 5.6.10 h. 5.6.10 i and 5.6.10 j. would be replaced with the following, as noted in italic type:
- h. The primary to secondaryLEAKAGE rate observed in each SG (if it is not practicalto assign the LEAKAGE to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report; and
- i. The calculatedaccidentinduced leakage rate from the portion of the tubes below 13.1 inches from the top of the tubesheet for the most limiting accidentin the most limiting SG. In addition,if the calculatedaccident induced leakage rate from the most limiting accident is less than 2 times the maximum operationalprimary to secondary leakage rate, the reportshould describe how it was determined.
- j. The results of monitoring for tube axial displacement(slippage). If slippage is discovered, the implicationsof the discovery and correctiveaction shall be provided.
3.0 Background VEGP consist of two four-loop Westinghouse designed plants with Model F steam generators, having 5626 tubes in each steam generator. A total (for all four steam generators per unit) of 121 tubes are currently plugged on Unit 1 and 43 on Unit 2. The design of the steam generator includes Alloy 600 thermally treated tubing, full depth hydraulically expanded tubesheet joints, and stainless steel tube support plates with broached hole quatrefoil.
The steam generator inspection scope is governed by TS 5.5.9, "Steam Generator (SG)
Program;" Nuclear Energy Institute (NEI) 97-06, "Steam Generator Program Guidelines,"
(Reference 6); EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," (Reference 7); EPRI 1012987, "Steam Generator Integrity Assessment Guidelines,"
(Reference 8); NMP-ES-004, "Steam Generator Program", and the results of the degradation assessments required by the Steam Generator Program. Criterion IX, "Control of Special Processes" of 10 CFR Part 50, Appendix B, requires in part that nondestructive testing be accomplished by qualified personnel using qualified procedures in accordance with the applicable criteria. The inspection techniques and equipment are capable of reliably detecting the known and potential specific degradation mechanisms applicable to VEGP. The inspection techniques, essential variables and equipment are qualified to Appendix H, "Performance Demonstration for Eddy Current Examination" of the EPRI Steam Generator Examination Guidelines.
Catawba Nuclear Station, Unit 2, (Catawba) reported indication of cracking following nondestructive eddy current examination of the steam generator tubes during their fall 2004 outage. NRC Information Notice (IN) 2005-09, "Indications in Thermally Treated Alloy 600 El -7
Enclosure 1 Basis for Proposed Change Steam Generator Tubes and Tube-to-Tubesheet Welds," (Reference 9), provided industry notification of the Catawba issue. IN 2005-09 noted that Catawba reported crack like indications in the tubes approximately seven inches below the top of the hot leg tubesheet in one tube, and just above the tube-to-tubesheet welds in a region of the tube known as the tack expansion in several other tubes. Indications were also reported in the tube-end welds, also known as tube-to-tubesheet welds, which join the tube to the tubesheet.
SNC policies and programs require the use of applicable industry operating experience in the operation and maintenance of VEGP. The recent experience at Catawba, as noted in IN 2005-09, shows the importance of monitoring all tube locations (such as bulges, dents, dings, and other anomalies from the manufacture of the steam generators) with techniques capable of finding potential forms of degradation that may be occurring at these locations (as discussed in Generic Letter 2004-001, "Requirements for Steam Generator Tube Inspections"). Since the VEGP Westinghouse Model F steam generators were fabricated with Alloy 600 thermally treated tubes similar to the Catawba Unit 2 Westinghouse Model D5 steam generators, a potential exists for VEGP to identify tube indications similar to those reported at Catawba within the hot leg tubesheet region if similar inspections are performed during the fall 2009 refueling outage.
Potential inspection plans for the tubes and tube welds underwent intensive industry discussions in March 2005. The findings in the Catawba steam generator tubes present three distinct issues with regard to the steam generator tubes at VEGP:
- 1) Indications in internal bulges and overexpansions within the hot leg tubesheet;
- 2) Indications at the elevation of the tack expansion transition; and
- 3) Indications in the tube-to-tubesheet welds and propagation of these indications into adjacent tube material.
Prior to each steam generator tube inspection, a degradation assessment, which includes a review of operating experience, is performed to identify degradation mechanisms that have a potential to be present in the VEGP steam generators. A validation assessment is also performed to verify that the eddy current techniques utilized are capable of detecting those flaw types that are identified in the degradation assessment. Based on operating experience discussed above, VEGP revised the steam generator inspection plan to include sampling of bulges and overexpansions within the tubesheet region on the hot leg side during Refueling Outage 1 R14 and 2R13 for Units 1 and 2, respectively. The sample is based on the guidance contained in EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," Revision 7, and TS 5.5.9, 'Steam Generator (SG) Program." The inspection plan was expanded according to EPRI steam generator examination guidelines if necessary due to confirmed degradation in the region required to be examined (i.e., a tube crack). Degradation was not detected in the tubesheet region in Refueling Outage 1 R14 and 2R13 for Units 1 and 2, respectively.
As a result of these potential issues and the possibility of unnecessarily plugging tubes in the VEGP steam generators, SNC is proposing changes to TS 5.5.9 to limit the steam generator tube inspection and repair (plugging) to the safety significant portion of the tubes.
E1-8
Enclosure 1 Basis for Proposed Change 4.0 Technical Evaluation To preclude unnecessarily plugging tubes in the VEGP steam generators, an evaluation was performed to identify the safety significant portion of the tube within the tubesheet necessary to maintain structural and leakage integrity in both normal and accident conditions. Tube inspections will be limited to identifying and plugging degradation in the safety significant portion of the tubes. The technical evaluation for the inspection and repair methodology is provided in WCAP-17071-P (Enclosure 5). The evaluation is based on the use of finite element model structural analysis and a bounding leak rate evaluation based on contact pressure between the tube and the tubesheet during normal and postulated accident conditions. The limited tubesheet inspection criteria were developed for the tubesheet region of the VEGP Model F steam generator considering the most stringent loads associated with plant operation, including transients and postulated accident conditions. The limited tubesheet inspection criteria were selected to prevent tube burst and axial separation due to axial pullout forces acting on the tube and to ensure that the accident induced leakage limits are not exceeded. WCAP-1 7071-P provides technical justification for limiting the inspection in the tubesheet expansion region to less than the full depth of the tubesheet.
The basis for determining the safety significant portion of the tube within the tubesheet is based upon evaluation and testing programs that quantified the tube-to-tubesheet radial contact pressure for bounding plant conditions as described in WCAP-17071-P. The tube-to-tubesheet radial contact pressure provides resistance to tube pullout and resistance to leakage during plant operation and transients.
Primary-to-secondary leakage from tube degradation in the tubesheet area is assumed to occur in several design basis accidents: feedwater line break (FLB), steam line break (SLB), locked rotor, and control rod ejection. The radiological dose'consequences associated with this assumed leakage are evaluated to ensure that they remain within regulatory limits. The accident induced leakage performance criteria are intended to ensure the primary-to-secondary leak rate during any accident does not exceed the primary-to-secondary leak rate assumed in the accident analysis. Radiological dose consequences define the limiting accident condition for the H* justification.
The constraint that is provided by the tubesheet precludes tube burst from cracks within the tubesheet. The criteria for tube burst described in NEI 97-06 and NRC Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," (Reference 10) are satisfied due to the constraint provided by the tubesheet. Through application of the limited tubesheet inspection scope as described below, the existing operating leakage limit provides assurance that excessive leakage (i.e., greater than accident analysis assumptions) will not occur. The accident induced leak rate limit is 1.0 gpm. The TS operational leak rate limit is 150 gpd (0.1 gpm) through any one steam generator. Consequently, there is significant margin between accident leakage and allowable operational leakage. The SLB/FLB leak rate ratio is only 2.03 resulting in significant margin between the conservatively estimated accident leakage and the allowable accident leakage (1.0 gpm).
Plant-specific operating conditions are used to generate the overall leakage factor ratios that are to be used in the condition monitoring and operational assessments. The plant-specific data provide the initial conditions for application of the transient input data. The results of the analysis of the plant-specific inputs, to determine the bounding plant for each model of steam El -9
Enclosure 1 Basis for Proposed Change generator, and to assure that the design basis accident contact pressures are greater than the normal operating pressure contact pressure are contained in Section 6 of Reference 5.
The leak rate ratio (accident induced leak rate to operational leak rate) is directly proportional to the change in differential pressure and inversely proportional to the dynamic viscosity. Since dynamic viscosity decreases with an increase in temperature, an increase in temperature results in an increase in leak rate.
However, for both the postulated SLB and FLB events, a plant cool down event would occur and the subsequent temperatures in the reactor coolant system (RCS) would not be expected to exceed the temperatures at plant no load conditions. Thus, an increase in leakage would not be expected to occur as a result of the viscosity change. The increase in leakage would only be a function of the increase in primary to secondary pressure differential. The resulting leak rate ratio for the SLB and FLB events is 2.03, which is the bounding value for all steam generator designs.
The other design basis accidents, such as the postulated locked rotor event and the control rod ejection event, are conservatively modeled using design specification transients which result in increased temperatures in the steam generator hot and cold legs for a period of time. As previously noted, dynamic viscosity decreases with increasing temperature. Therefore, leakage would be expected to increase due to decreasing viscosity, as well as due to the increasing differential pressure, for the duration of time that there is a rise in RCS temperature. For transients other than a SLB and FLB, the length of time that a plant with Model F steam generators will exceed the normal operating differential pressure across the tubesheet is less than 30 seconds. As the accident induced leakage performance criteria is defined in gallons per minute, the leak rate for a locked rotor event can be integrated over a minute to compare to the limit. Time integration permits an increase in acceptable leakage during the time of peak pressure differential by approximately a factor of two because of the short duration (less than 30 seconds) of the elevated pressure differential. This translates into an effective reduction in leakage factor by the same factor of two for the locked rotor event. Therefore, for the locked rotor event, the leakage factor of 1.74 (Table 9-7, Reference 5) for VEGP is adjusted downward to a factor of 0.87. Similarly, for the control rod ejection event, the duration of the elevated pressure differential is less than 10 seconds. Thus, the peak leakage factor may be reduced by a factor of six from 2.62 to 0.44.
The plant transient response following a full power double-ended main feedwater line rupture corresponding to "best estimate" initial conditions and operating characteristics indicates that the transient for a Model F steam generator exhibits a cool down characteristic instead of a heat-up transient as generally presented in steam generator design transients and in the UFSAR Chapter 15.0 safety analysis. The use of either the component design specification transient or the Chapter 15.0 safety transient for leakage analysis for FLB is overly conservative because:
The assumptions on which the FLB design transient is based are specifically intended to establish a conservative structural (fatigue) design basis for reactor coolant system components; however, H* does not involve component structural and fatigue issues. The best estimate transient is considered more appropriate for use in the H* leakage calculations.
For the Model F steam generator, the FLB transient curve (Figure 9-5, Reference 5) represents a double-ended rupture of the main feedwater line concurrent with both loss of El-10
Enclosure 1 Basis for Proposed Change offsite power (loss of main feedwater and reactor coolant pump coast down) and turbine trip.
The assumptions on which the FLB safety analysis is based are specifically intended to establish a conservative basis for minimum auxiliary feedwater (AFW) capacity requirements and combines worst case assumptions which are exceptionally more severe when the FLB occurs inside containment. For example, environmental errors that are applied to reactor trip and engineered safety feature actuation would be less severe. This would result in much earlier reactor trip and greatly increase the steam generator liquid mass available to provide cooling to the RCS.
A SLB event would have similarities to a FLB except that the break flow path would include the secondary separators, which could only result in an increased initial cooldown (because of retained liquid inventory available for cooling) when compared to the FLB transient. A SLB could not result in more limiting RCS temperature conditions than a FLB.
In accordance with plant operating procedures, the operator would take action following a high energy secondary line break to stabilize the RCS conditions. The expectation for a SLB or FLB with credited operator action is to stop the system cooldown through isolation of the faulted steam generator and control of temperature by the AFW system. Steam pressure control would be established by either the steam generator safety valves or control system (atmospheric relief valves). For any of the steam pressure control operations, the maximum RCS temperature would be approximately the no load temperature and would be well below normal operating temperature.
Since the best estimate FLB transient temperature would not be expected to exceed the normal operating temperature, the viscosity ratio for the FLB transient is set to 1.0.
The leakage factor of 2.02 for VEGP, for a postulated SLB/FLB, has been calculated as shown in Table 9-7 of Reference 5. The leakage factor of 2.03 is a bounding value for all steam generators, both hot and cold legs, in Table 9-7 of Reference 5. Specifically, for the condition monitoring (CM) assessment, the component of leakage from the prior cycle from below the H*
distance will be multiplied by a factor of 2.03 and added to the total leakage from any other source and compared to the allowable accident induced leakage limit. For the operational assessment (OA), the difference in the leakage between the allowable leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 2.03 and compared to the observed operational leakage.
Reference 5 redefines the primary pressure boundary. The tube-to-tubesheet weld no longer functions as a portion of this boundary. The hydraulically expanded portion of the tube into the tubesheet over the H* distance now functions as the primary pressure boundary in the area of the tube and tubesheet, maintaining the structural and leakage integrity over the full range of steam generator operating conditions, including the most limiting accident conditions. The evaluation in Reference 5 determined that degradation in tubing below this safety significant portion of the tube does not require inspection or repair (plugging). The inspection of the safety significant portion of the tubes provides a high level of confidence that the structural and leakage performance criteria are maintained during normal operating and accident conditions.
WCAP-1 7071 -P, section 9.8, provides a review of leak rate susceptibility due to tube slippage and concluded that the tubes are fully restrained against motion under very conservative design El-11
Enclosure 1 Basis for Proposed Change and analysis assumptions such that tube slippage is not a credible event for any tube in the bundle. However, in response to a NRC staff request, SNC commits to monitor for tube slippage as part of the steam generator tube inspection program.
In addition the NRC staff has requested that licensees perform a validation of the tube expansion from the top of tubesheet to the beginning of expansion transition (BET) to determine if there are any significant deviations that would invalidate assumptions in WCAP-17071-P.
Therefore, SNC commits to perform a one time verification of tube expansion to locate any significant deviations from the top of tubesheet to the beginning of expansion transition (BET). If any significant deviations are found, the condition will be entered into the plants corrective action program and dispositioned.
5.0 Regulatory Evaluation 5.1 Applicable Regulatory Requirements/Criteria General Design Criteria (GDC) 1, 2, 4, 14, 30, 31, and 32 of 10 CFR 50, Appendix A, define requirements for the reactor coolant pressure boundary (RCPB) with respect to structural and leakage integrity.
GDC 19 of 10 CFR 50, Appendix A, defines requirements for the control room and for the radiation protection of the operators working within it. Accidents involving the leakage or burst of steam generator tubing comprise a challenge to the habitability of the control room.
10 CFR 50, Appendix B, establishes quality assurance requirements for the design, construction, and operation of safety related components. The pertinent requirements of this appendix apply to all activities affecting the safety related functions of these components.
These requirements are described in Criteria IX, XI, and XVI of Appendix B and include control of special processes, inspection, testing, and corrective action.
10 CFR 100, Reactor Site Criteria, established reactor siting criteria, with respect to the risk of public exposure to the release of radioactive fission products. Accidents involving leakage or tube burst of steam generator tubing may comprise a challenge to containment and therefore involve an increased risk of radioactive release.
Under 10 CFR 50.65, the Maintenance Rule, licensees classify steam generators as risk significant components because they are relied upon to remain functional during and after design basis events. Steam generators are to be monitored under 10 CFR 50.65(a)(2) against industry established performance criteria. Meeting the performance criteria of NEI 97-06, Revision 2, provides reasonable assurance that the steam generator tubing remains capable of fulfilling its specific safety function of maintaining the reactor coolant pressure boundary. The NEI 97-06, Revision 2, steam generator performance criteria are:
All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident El-12
Enclosure 1 Basis for Proposed Change primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design and licensing basis, shall also be evaluated to determine ifthe associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial loads.
The primary to secondary accident induced leakage rate for any design basis accident, other than a steam generator tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all steam generators and leakage rate for an individual steam generator. Leakage is not to exceed 1.0 gpm per steam generator, except for specific types of degradation at specific locations when implementing alternate repair criteria as documented in the Steam Generator Program technical specifications.
" The RCS operational primary-to-secondary leakage through any one steam generator shall be limited to 150 gallons per day.
The safety significant portion of the tube is the length of tube that is engaged in the tubesheet from the secondary face that is required to maintain structural and leakage integrity over the full range of steam generator operating conditions, including the most limiting accident conditions.
The evaluation in this Enclosure determined that degradation in tubing below the safety significant portion of the tube does not require plugging and serves as the bases for the tubesheet inspection program. As such, the VEGP inspection program provides a high level of confidence that the structural and leakage criteria are maintained during normal operating and accident conditions.
5.2 No Significant Hazards Consideration This amendment application proposes to revise Technical Specification (TS) 5.5.9, "Steam Generator (SG) Program," to exclude portions of the tubes within the tubesheet from periodic steam generator inspections. In addition, this amendment proposes to revise Technical Specification (TS) 5.6.10, "Steam Generator Tube Inspection Report" to remove reference to previous interim alternate repair criteria and provide reporting requirements specific to the permanent alternate repair criteria. Application of the structural analysis and leak rate evaluation results, to exclude portions of the tubes from inspection and repair is interpreted to constitute a redefinition of the primary-to-secondary pressure boundary.
The proposed change defines the safety significant portion of the tube that must be inspected and repaired. A justification has been developed by Westinghouse Electric Company, LLC to identify the specific inspection depth below which any type of axial or circumferential primary water stress corrosion cracking can be shown to have no impact on Nuclear Energy Institute (NEI) 97-06, "Steam Generator Program Guidelines," (Reference 6) performance criteria.
SNC has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:
E1-13
Enclosure 1 Basis for Proposed Change
- 1) Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No The previously analyzed accidents are initiated by the failure of plant structures, systems, or components. The proposed change that alters the steam generator inspection criteria and the steam generator inspection reporting criteria does not have a detrimental impact on the integrity of any plant structure, system, or component that initiates an analyzed event. The proposed change will not alter the operation of, or otherwise increase the failure probability of any plant equipment that initiates an analyzed accident.
Of the applicable accidents previously evaluated, the limiting transients with consideration to the proposed change to the steam generator tube inspection and repair criteria are the steam generator tube rupture (SGTR) event and the feedline break (FLB) postulated accidents.
During the SGTR event, the required structural integrity margins of the steam generator tubes and the tube-to-tubesheet joint over the H* distance will be maintained. Tube rupture in tubes with cracks within the tubesheet is precluded by the constraint provided by the tube-to-tubesheet joint. This constraint results from the hydraulic expansion process, thermal expansion mismatch between the tube and tubesheet, and from the differential pressure between the primary and secondary side. Based on this design, the structural margins against burst, as discussed in Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes,"(Reference 10) are maintained for both normal and postulated accident conditions.
The proposed change has no impact on the structural or leakage integrity of the portion of the tube outside of the tubesheet. The proposed change maintains structural integrity of the steam generator tubes and does not affect other systems, structures, components, or operational features. Therefore, the proposed change results in no significant increase in the probability of the occurrence of a SGTR accident.
At normal operating pressures, leakage from primary water stress corrosion cracking below the proposed limited inspection depth is limited by both the tube-to-tubesheet crevice and the limited crack opening permitted by the tubesheet constraint.
Consequently, negligible normal operating leakage is expected from cracks within the tubesheet region. The consequences of an SGTR event are affected by the primary-to-secondary leakage flow during the event. However, primary-to-secondary leakage flow through a postulated broken tube is not affected by the proposed changes since the tubesheet enhances the tube integrity in the region of the hydraulic expansion by precluding tube deformation beyond its initial hydraulically expanded outside diameter.
Therefore, the proposed changes do not result in a significant increase in the consequences of a SGTR.
The consequences of a steam line break (SLB) are also not significantly affected by the proposed changes. During a SLB accident, the reduction in pressure above the tubesheet on the shell side of the steam generator creates an axially uniformly distributed load on the tubesheet due to the reactor coolant system pressure on the underside of the tubesheet.
E1-14
Enclosure 1 Basis for Proposed Change The resulting bending action constrains the tubes in the tubesheet thereby restricting primary-to-secondary leakage below the midplane.
Primary-to-secondary leakage from tube degradation in the tubesheet area during the limiting accident (i.e., a SLB) is limited by flow restrictions. These restrictions result from the crack and tube-to-tubesheet contact pressures that provide a restricted leakage path above the indications and also limit the degree of potential crack face opening as compared to free span indications.
The leakage factor of 2.02 for Vogtle Electric Generating Plant (VEGP), for a postulated SLB/FLB, has been calculated as shown in Table 9-7 of Reference 5. The leakage factor of 2.03 is a bounding value for all steam generators, both hot and cold legs, in Table 9-7 of Reference 5. Specifically, for the condition monitoring (CM) assessment, the component of leakage from the prior cycle from below the H* distance will be multiplied by a factor of 2.03 and added to the total leakage from any other source and compared to the allowable accident induced leakage limit. For the operational assessment (OA), the difference in the leakage between the allowable leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 2.03 and compared to the observed operational leakage.
The probability of a SLB is unaffected by the potential failure of a steam generator tube as the failure of the tube is not an initiator for a SLB event. SLB leakage is limited by leakage flow restrictions resulting from the leakage path above potential cracks through the tube-to-tubesheet crevice. The leak rate during postulated accident conditions (including locked rotor) has been shown to remain within the accident analysis assumptions for all axial and or circumferentially orientated cracks occurring 13.1 inches below the top of the tubesheet. The accident induced leak rate limit is 1.0 gpm. The TS operational leak rate is 150 gpd (0.1 gpm) through any one steam generator. Consequently, there is significant margin between accident leakage and allowable operational leakage. The SLB/FLB leak rate ratio is only 2.03 resulting in significant margin between the conservatively estimated accident leakage and the allowable accident leakage (1.0 gpm).
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
- 2) Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No The proposed change that alters the steam generator inspection criteria and the steam generator inspection reporting criteria does not introduce any new equipment, create new failure modes for existing equipment, or create any new limiting single failures. Plant operation will not be altered, and all safety functions will continue to perform as previously assumed in accident analyses.
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
- 3) Does the change involve a significant reduction in a margin of safety?
El-15
Enclosure 1 Basis for Proposed Change Response: No The proposed change that alters the steam generator inspection criteria and the steam generator inspection reporting criteria maintains the required structural margins of the steam generator tubes for both normal and accident conditions NEI 97-06, Revision 2, "Steam Generator Program Guidelines" (Reference 6) and RG 1.121, are used as the bases in the development of the limited tubesheet inspection depth methodology for determining that steam generator tube integrity considerations are maintained within acceptable limits. RG 1.121 describes a method acceptable to the NRC for meeting GDC 14, "Reactor Coolant Pressure Boundary," GDC 15, "Reactor Coolant System Design,"
GDC 31, "Fracture Prevention of Reactor Coolant Pressure Boundary," and GDC 32, "Inspection of Reactor Coolant Pressure Boundary," by reducing the probability and consequences of a SGTR. RG 1.121 concludes that by determining the limiting safe conditions for tube wall degradation the probability and consequences of a SGTR are reduced. This RG uses safety factors on loads for tube burst that are consistent with the requirements of Section III of the American Society of Mechanical Engineers (ASME)
Code.
For axially oriented cracking located within the tubesheet, tube burst is precluded due to the presence of the tubesheet. For circumferentially oriented cracking, WCAP-17071-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)," defines a length of degradation free.
expanded tubing that provides the necessary resistance to tube pullout due to the pressure induced forces, with applicable safety factors applied. Application of the limited hot and cold leg tubesheet inspection criteria will preclude unacceptable primary-to-secondary leakage during all plant conditions. The methodology for determining leakage provides for large margins between calculated and actual leakage values in the proposed limited tubesheet inspection depth criteria.
Therefore, the proposed change does not involve a significant reduction in any margin of safety.
5.3 Conclusion The safety significant portion of the tube is the length of tube that is engaged within the tubesheet to the top of the tubesheet (secondary face) that is required to maintain structural and leakage integrity over the full range of steam generating operating conditions, including the most limiting accident conditions. WCAP-1 7071-P determined that degradation in tubing below the safety significant portion of the tube does not require plugging and serves as the basis for the limited tubesheet inspection criteria, which are intended to ensure the primary-to-secondary leak rate during any accident does not exceed the leak rate assumed in the accident analysis.
Based on the considerations above, 1) there is a reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, 2) such activities will be conducted in compliance with the Commission's regulations, and 3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
E1-16
Enclosure 1 Basis for Proposed Change 6.0 Environmental Considerations SNC has evaluated the proposed amendment for envirornmental considerations. The review has resulted in the determination that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, and would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendments meet the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.
E1-17
Enclosure 1 Basis for Proposed Change 7.0 References
- 1. Vogtle Electric Generating Plant Units 1 and 2, "RE: Issuance of Amendments Regarding the Steam Generator Tube Surveillance Program," September 21, 2005, (TAC Nos. MC8078 and MC8079).
- 2. Vogtle Electric Generating Plant Units 1 and 2, "Issuance of Amendments Regarding the Steam Generator Tube Surveillance Program," September 12, 2006, (TAC Nos.
MD2642 and MD2643).
- 3. Vogtle Electric Generating Plant Units 1 and 2, "Issuance of Amendments Regarding Changes to Technical Specification (TS) Sections TS 5.5.9, "Steam Generator (SG)
Program" and TS 5.6.10, "Steam Generator Tube Inspection Report," April 9, 2008, (TAC Nos. MD7450 and MD7451).
- 4. Vogtle Electric Generating Plant Units 1 and 2, "Issuance of Amendments Regarding Steam Generator Tube Inspection Program," September 16, 2008, (TAC Nos. MD9148 and MD9149).
- 5. Westinghouse Electric Company LLC, WCAP-17071-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)."
- 6. NEI 97-06, Rev. 2, "Steam Generator Program Guidelines," May 2005.
- 7. EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines."
- 8. EPRI 1012987; "Steam Generator Integrity Assessment Guidelines".
- 9. NRC Information Notice (IN) 2005-09, "Indications in Thermally Treated Alloy 600 Steam Generator Tubes and Tube-to-Tubesheet Welds."
- 10. Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes,"
dated August 1976, (ADAMS Accession No. ML003739366).
El-18
Vogtle Electric Generating Plant Units 1 and 2 License Amendment Request to Revise Technical Specification (TS)
Sections 5.5.9, "Steam Generator (SG) Program" and TS 5.6.10, "Steam Generator Tube Inspection Report" for Permanent Alternate Repair Criteria Enclosure 2 Markup of Proposed Technical Specifications
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)
- 2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm per SG.
- 3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."
- c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.
Insert 1 The following alternate tube repair criteria shall be applied as an Iternative to the 40% depth based criteria:
I.For. Unit 2 during Refueling Outage I1I and- tho- GubSequon8t op38rating cyGeo, degrada*,, found in the p*ortio of the tu3,beboow 17 inches from; the top of the hot leg tubesheet doeS no~t requiro plugging-.
Fo-r- Unmfit -2durFing Rofuol~ing Outage 11 and the 6ubsequon~t operating cycle, degradatinr id*ntified in the portinr of the tube from the top of the hot leg tubosheet to 17 inches below the top of the tubeshect shall be plugged upon detection.
- 2. FoA-r UniAt 1 during Refueling Outage 13 and- the subsequent operating cycle, and for Unit 2 during Refucling Outage 12 and the subsequent operating cycle, degradation identified in the portion Of the tube belowA.
17 inches from the top of the het leg tubesheet dee no r,equire Fo~r Unimt I during Refueling Outage 13 anRd the suibsequent eperating cycle, and-fo-r Unit -2dur~ing Refueling Outage 12 and the su bsequent operating cycle, degradation identified in the portion of the tube from the top of the hot leg tubeshect to 17 inches below the top ef the hot leg tulbesheeAt shall bet- plugged upon de~tectin.
. For Unit 1 dFri*g Refueling Outage 14 anpd the subsequent operatiRg cycle and for Unit 2 during Refueling Outage 13 and the subsequent operating cycle, tubes with flaws havin a circumferetial1 coA-mponent less than or equal to 203 degrees found in the portion of the tube below 17 inches fromR the top of the tubesheet and above 1 inch fromF the (continued)
Vogtle Units 1 and 2 5.5-8 Amendment No. (Unit 1)
Amendment No. (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Pro-gram (continued) bottom of the tubcsheet do) not require plugging. Tubos with fl-iaws having a circumnferential component greater than 203 degrees four the por-tion of the tube below 17 inches fromR the top of the tubheshe anR~d_ ;-Abovo 1 inch from. the botto-m of tho; tubehshoot hall be re~mnv f~oR em-ee.Ae pet Tubo hwith seR9Gice iduce~d flaws located Within tho 'rogion fromR thc of the tubesheet to 17 inhsbelow the top of the tubesheet shall romoved froam. servic~re. Tubes with Ger.ice induc~ed axial cracks foi inR the porFtion of the tube below 17 inches from; the top of the tubes do no~t require pluggingý. 4Rd 4hee W.hen more than one flaw with circumnferential comfpoenets isfoun' the portion of the tube below 17 inc-hes; fro~m the top of the tubeshe and aboeo 1 inhfrom the bottom of the tubesheot with the total of crcur, mferentia copoentS greater thanp 203 degrees and an axial 'et separation dlistance of le~ss than;Ip 1.inch, then the tubbe s.hall bhe rom:
fro~m servidc-e. W~hen the- c~ircuIm~fA.eretial components, of eac;h of tht; flaws are added, it is acceptable te count the overlapped portions onAe in the total Of circumnferential comRponents.
W.~henp onoe or moefawswth crcum qferenRtial components areS feunI
)4Rl the portion of the tulbe w.ithin 1Inc frem the bottom of the tubeshc and the total Of the circumnf8eretial com~ponents found in the tube exceeds 94 degrees, then the tube shall be removed fro~m sevie d OR W~hen o~ne erF mereFp flaws wtciumferentia;l compoents are fun--,
the portion of the tube within 1 inc-h fro-m. the bottom of the tubeshc and within 1 inc-h -axialseparation distance of a flaw above 1 inch f 2 .nsert the bottom of the tubesheet, and the total of the6m circuferenia c)Mpenen.ts_ foun-d- in the tubhe eods94 degrees, then the tu-Ibe sha I be emve fromn Eservfice. When the circumnferential com~poenRPts A each of the flaws are added, it is acceptable to coun~t the EoVerlapp portions only once in the= toal of cFircumferentia comnponents.
k
- d. ::,-,,;;*nfG_ .F * - ;nSra;-t;-** Pe idnr,-, G;- SGp tu.be ;nRnp ,,'t;,-,R Sh-all be
,'fermed. The numhber and portions of the tubes i;npected and methods qf inspection shall be perfermed- wAith the objective of detecting flaws of any
.ype (e.g., volumetric flaws, axial aRnd Gcircumferental crc*ks) that m.ay be qrecn{t along the length of the tube, from th tub to tubesheet weld at he tube inlet to the tube to tubocheet weld at the tube outlet, and that may,
,atisfy the applicable tube epai;r criteFia. For Unit 2 dhring Refueling Dutage 11 and the subsequent operating cycle, the portion of the- tube11 (continued)
Vogtle Units 1 and 2 5.5-9 Amendment No. (Unit 1)
Amendment No. (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) f Ii
- F iI i I I DelOw 1 Innes I In*
1 e;4iurin Drf, trom
,pilin the top OT the not leg wUDosneet is exciuaea. ,-or
('.m+n ^ 'I .np thp *,*unn+ ^,.rnfinr n n*l
%I 11 11 - -..- V m Y I cYcle, .th prtion.of the tube beow 17 inches from. the top of the.hot.leg I L
ue os. 'i ne tube-to-tuoesneet weld is not part oT me tuoe.
In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.
- 2. Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for Insert 3 more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.
3.
_k IfcrcindicationS are found in any SG tube, then the next inspection for each SG- for t-he degr~adatioR nmechanism that caused the crack inRdication shall not exc-eed- 24 e-ffective full poweNPr months or one refueling outage (Whichever is loss). ifdefinitive information, such as-frmex-aminationA of a pulled tube, diagnostic nondeRStruc-tive testing, orF enierig evaluation indic~ates that a crack lke iniato is nt assciaedwith a crack(s), then the indication need not be treated as a G~aGk.
- e. Provisions for monitoring operational primary to secondary LEAKAGE.
5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:
(continued)
Vogtle Units 1 and 2 5.5-10 Amendment No. (Unit 1)
Amendment No. (Unit 2)
Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Deleted.
5.6.10 Steam Generator Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program. The report shall include:
- a. The scope of inspections performed on each SG,
- b. Active degradation mechanisms found,
- c. Nondestructive examination techniques utilized for each degradation mechanism,
- d. Location, orientation (if linear), and measured sizes (if available) of service induced indications,
- e. Number of tubes plugged during the inspection outage for each active degradation mechanism, I
- f. Total number and percentage of tub ged to date,
- g. The results iion monitoring, including the results of tube pulls and in-situ testing,
- h. F i pletion of a Unit 1 inspection performed in Rofuoling Outage 14 (and an" inspections, performed in the subsequent o~perating cycle) and following comnpletioni of a 61Ri . InspccIion periOrmeu4 in Kcrueiing Outage Ai la ka any inspeGIions peFnOFrmcu in Me subsequen~t operating cycle), the numRbe-r oef iniatosand oation, size, orientation, whether initiated on primary Or secondary side for each service induced flaw within the thickness of the tubeshoet, and the total of the circumiferential components and anyV circumFferential overlap below1. 17 fincahes from the top of the tubesheet as, determined i accordance with TS 5.5(.9.3;"
- i. FI9ollWoig pletion ofI a lI Unit* performed
- inspection I in R Outage 1 lefulnlag (and aRy ins~pections performned in the subsequent operatfing cycle) and following completion of a Unit 2 inspectfion performed in Refueling Outage 13 (and any inspections per~formed inthe subsequIent operating cycle), the primnary to SecOndar,' LEAKAGE rate observePd ine-ac;-h SG (if it is no~t practical to assignl leakage to an nivda SG, the entire primnary to seconRdarY LEAKA.GE should be8 consrvaivl assumed to be from one 5G) durin the cyci Drceaig meinsectiQnA wn~ficnh &iBe uecOTnRepot FAIana
- j. 1 61100" RZI - - I ... . . ý kdFIFJ Wly I.
I i !Inecin
.... r ........ fe~rmiea in tme ; Wsu~oseouenpora4mina cyce)an r oI4An iiowino rcomoimion At- A ii (continued)
Vogtle Units 1 and 2 5.6-6 Amendment No. *(Unit 1)
Amendment No. M--(Unit 2)
Reporting Requirements 5.6 5.6 Reporting Requirements Requirements Reporting 5.Aj.1 5.6 6team Uenerator T ube Inc~ectiE)n hReper (continued)
Bi wl
- subseqUeRnt o*prating hcyc), tho calc*lated accideRt lakage Fate trom thie porion Of thie tuoe below 17 inc-hes fro-m the top of the tubeshoot for the mocst limiting accident in the moESt iOmitinFg
/" #"* "*e Veaue uniISA aREI zz n.e(acum I-A n eR.~-R4-IU. 4ag uIRin Aj A
A.M.nmn PA -PP AI P A. 4 ij (uni1t .z)
Insert 1:
Tubes with service-induced flaws located greater than 13.1 inches below the top of the tubesheet do not require plugging. Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 13.1 inches below the top of the tubesheet shall be plugged upon detection.
Insert 2:
Provisions for SG tube inspections. Periodic SG tube inspections shall be performed.
The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present, from 13.1 inches below the top of tubesheet on the hot leg side to 13.1 inches below the top of the tubesheet on the cold leg side, and that may satisfy the applicable tube repair criteria.
Insert 3:
If crack indications are found from 13.1 inches below the top of tubesheet on the hot leg side to 13.1 inches below the top of the tubesheet on the cold leg side, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic nondestructive testing, or engineering evaluatiorn indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.
Insert 4:
- h. The primary to secondary LEAKAGE rate observed in each SG (if it is not practical to assign the LEAKAGE to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report; and
- i. The calculated accident induced leakage rate from the portion of the tubes below 13.1 inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, ifthe calculated accident induced leakage rate from the most limiting accident is less than 2 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined.
- j. The results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.
Vogtle Electric Generating Plant Units 1 and 2 License Amendment Request to Revise Technical Specification (TS)
Sections 5.5.9, "Steam Generator (SG) Program" and TS 5.6.10, "Steam Generator Tube Inspection Report" for Permanent Alternate Repair Criteria Enclosure 3 Typed Pages for Technical Specification
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)
- 2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm per SG.
- 3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."
- c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.
The following alternate tube repair criteria shall be applied as an alternative to the 40% depth based criteria:
Tubes with service-induced flaws located greater than 13.1 inches below the top of the tubesheet do not require plugging. Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 13.1 inches below the top of the tubesheet shall be plugged upon detection.
(continued)
Vogtle Units 1 and 2 5.5-8 Amendment No. (Unit 1)
Amendment No. (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)
- d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present, from 13.1 inches below the top of tubesheet on the hot leg side to 13.1 inches below the top of the tubesheet on the cold leg side, and that may satisfy the applicable tube repair criteria.
(continued)
Vogtle Units 1 and 2 5.5-9 Amendment No. (Unit 1)
Amendment No. (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)
The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.
- 2. Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.
- 3. If crack indications are found from 13.1 inches below the top of tubesheet on the hot leg side to 13.1 inches below the top of the tubesheet on the cold leg side, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic nondestructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.
- e. Provisions for monitoring operational primary to secondary LEAKAGE.
5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:
(continued)
Vogtle Units 1 and 2 5.5-10 Amendment No. (Unit 1)
Amendment No. (Unit 2)
Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Deleted.
5.6.10 Steam Generator Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program. The report shall include:
- a. The scope of inspections performed on each SG,
- b. Active degradation mechanisms found,
- c. Nondestructive examination techniques utilized for each degradation mechanism,
- d. Location, orientation (if linear), and measured sizes (if available) of service induced indications,
- e. Number of tubes plugged during the inspection outage for each active degradation mechanism,
- f. Total number and percentage of tubes plugged to date,
- g. The results of condition monitoring, including the results of tube pulls and in-situ testing,
- h. The primary to secondary LEAKAGE rate observed in each SG (if it is not practical to assign the LEAKAGE to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report; and
- i. The calculated accident induced leakage rate from the portion of the tubes below 13.1 inches from the top of the tubesheet for the most limiting accident in the most limiting SG.
In addition, if the calculated accident induced leakage rate from the most limiting accident is less than 2 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined.
- j. The results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.
Vogtle Units 1 and 2 5.6-6 Amendment No. (Unit 1)
Amendment No. (Unit 2)
Vogtle Electric Generating Plant Units 1 and 2 License Amendment Request to Revise Technical Specification (TS)
Sections 5.5.9, "Steam Generator (SG) Program" and TS 5.6.10, "Steam Generator Tube Inspection Report" for Permanent Alternate Repair Criteria Enclosure 4 List of Regulatory Commitments
List of Regulatory Commitments The following table identifies those actions committed by Southern Nuclear Operating Company in this document for Vogtle Electric Generating Plant. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments.
Commitment Due Date/Event SNC commits to monitor for tube slippage as part of the steam Prior to the start of generator tube inspection program. Refueling Outage 1R15 SNC commits to perform a one time verification of tube Prior to the startup expansion to locate any significant deviations from the top of following Refueling tubesheet to the beginning of. expansion transition (BET). If Outage 1 R15 (Unit any significant deviations are found, the condition will be 1) and 2R14 (Unit 2).
entered into the plants corrective action program and dispositioned.