NL-10-1513, Emergency Technical Specification Revision Request for TS 3.7.9 Ultimate Heat Sink - Nuclear Service Cooling Water Tower Fan

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Emergency Technical Specification Revision Request for TS 3.7.9 Ultimate Heat Sink - Nuclear Service Cooling Water Tower Fan
ML102210181
Person / Time
Site: Vogtle Southern Nuclear icon.png
Issue date: 08/04/2010
From: Ajluni M
Southern Nuclear Operating Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-10-1513
Download: ML102210181 (42)
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Text

Southern Nuclear -

Operating Company, Inc.

40 Inverness Center Parkway Post Office Box 1295 Birmingham, Alabama 35201-1295 Tel 205.992.5000 August 4, 2010 SOUTHERN COMPANY Energy to Serve Your Worid" Docket Nos.: 50-424 NL-10-1513 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Vogtle Electric Generating Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.7.9 Ultimate Heat Sink - Nuclear Service Cooling Water Tower Fan Ladies and Gentlemen:

Pursuant to 10 CFR 50.90 and 10 CFR 50.91 (a)(5), Southern Nuclear Operating Company (SNC), hereby requests an emergency amendment to Vogtle Electric Generating Plant (VEGP) Unit 1 Operating License NPF-68. The proposed change to the Technical Specifications (TS) contained herein would revise TS 3.7.9, "Ultimate Heat Sink (UHS)" such that, with one Nuclear Service Cooling Water (NSCW) cooling tower fan inoperable, the allowed completion time for Condition B is extended from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days, on a one-time only basis. The 7 day allowable outage time will allow time to repair the Unit 1 B-train NSCW cooling tower fan #3.

This change should be processed as an emergency change to prevent an unscheduled shutdown of Vogtle Unit 1 for a condition that is assessed as low risk.

The Unit 1 B-train NSCW cooling tower fan #3 was declared inoperable on August 3, 2010 at 0834 hours0.00965 days <br />0.232 hours <br />0.00138 weeks <br />3.17337e-4 months <br />, when maintenance personnel noticed abnormal noise from the gearbox. SNC has a replacement gearbox on site and work to install it is in progress. However, gearbox replacement involves several major activities, and the outdoor location and relative inaccessibility of the gearbox atop the NSCW cooling tower add complexity to this task. Completion of these activities is anticipated to require more than the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowable outage time (which will expire at 0834 hours0.00965 days <br />0.232 hours <br />0.00138 weeks <br />3.17337e-4 months <br /> on August 6, 2010) and so this one-time emergency TS amendment is requested.

A discussion of the proposed TS change, the basis for the change and Significant Hazards Considerations are provided in Enclosure 1. SNC has evaluated the proposed TS change and has determined that it does not involve a significant hazards consideration as defined in 10 CFR 50.92. In addition, a risk evaluation has been performed to show that the incremental risk for the proposed change is acceptable. The risk evaluation is provided in Enclosure 2.

SNC has also determined that operation with the proposed change will not result in any significant increase in the amount of effluents that may be released offsite and no significant increase in individual or cumulative occupational radiation exposure. Therefore, the proposed amendment is eligible for categorical

U. S. Nuclear Regulatory Commission NL-10-1513 Page 2 exclusion as set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment is needed in connection with the approval of the proposed change. The basis for that determination is also provided in Enclosure 1. The marked-up and clean typed proposed TS pages are provided in Enclosures 3 and 4, respectively.

To avoid an unnecessary plant shutdown, SNC requests that the proposed TS change be reviewed and approved by 0834 hours0.00965 days <br />0.232 hours <br />0.00138 weeks <br />3.17337e-4 months <br /> on August 6, 2010. The extended Unit 1 Completion time will expire upon returning 1B NSCW cooling tower fan #3 to operable status or on August 10, 2010 at 0834 hours0.00965 days <br />0.232 hours <br />0.00138 weeks <br />3.17337e-4 months <br />, whichever occurs first.

Mr. M. J. Ajluni states he is Nuclear Licensing Director 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.

This letter contains no NRC commitments. If you have any questions, please contact Ms. Tracy Honeycutt at (205)992-6896.

Respectfully submitted, M. J. Ajluni Nuclear Licensing Director Sworn to and subscribed before me thisj day of P, A_ 2010.

Notary Public My commission expires: I /93 -2 o MJA/DWD/lac : Description of the Proposed Change : August 3, 2010 Memo re Risk-Based Analysis RBA 10-011-V : Marked-Up Technical Specifications Page : Clean Typed Technical Specifications Page cc: Southern Nuclear Operatingq 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 NL-10-1513 Page 3 U. S. Nuclear Requlatory Commission Mr. L. A. Reyes, Regional Administrator Mr. R. E. Martin, NRR Project Manager - Vogtle Mr. M. Cain, Senior Resident Inspector - Vogtle Mr. P.G. Boyle, NRR Project Manager State of Georqia Mr. C. Clark, Commissioner - Department of Natural Resources

Vogtle Electric Generating Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.7.9 Ultimate Heat Sink - Nuclear Service Cooling Water Tower Fan Enclosure 1 Description of the Proposed Change

Vogtle Electric Generating Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.7.9 Ultimate Heat Sink - Nuclear Service Coolinq Water Tower Fan Enclosure 1 Description of the Proposed Change Table of Contents 1.0 Introduction

2.0 Background

3.0 Need for Technical Specification Change 4.0 Description of Proposed Change 4.1 Proposed Change

4.2 System Description

4.3 Basis for the Technical Specification Change 5.0 Risk Assessment 6.0 Regulatory Safety Analysis 6.1 No Significant Hazards Consideration 6.2 Environmental Assessment 7.0 Conclusion

Enclosure 1 Description of the Proposed Change 1.0 Introduction Pursuant to 10 CFR 50.90 and 10 CFR 50.91 (a)(5), Southern Nuclear Operating Company (SNC), hereby requests an emergency amendment to Vogtle Electric Generating Plant (VEGP) Unit 1 Operating License NPF-68. The proposed change to the Technical Specifications (TS) contained herein would revise TS 3.7.9, "Ultimate Heat Sink" such that, with one Nuclear Service Cooling Water (NSCW) cooling tower fan inoperable, the allowed completion time for Condition B is extended from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days, on a one-time only basis. This change should be processed as an emergency change to prevent an unscheduled shutdown of Vogtle Unit 1.

The proposed change qualifies for categorical exclusion from an environmental assessment as set forth in 10 CFR 51.22(c)(9). Therefore, no environmental impact statement or environmental assessment is needed in connection with the approval of the proposed change.

2.0 Background The Unit 1 B-train NSCW cooling tower fan #3 (tag #1-1202-W4-002-F03) was declared inoperable on August 3, 2010 at 0834 hours0.00965 days <br />0.232 hours <br />0.00138 weeks <br />3.17337e-4 months <br />, when maintenance personnel noticed abnormal noise from the gearbox. Technical Specification 3.7.9 requires four of four NSCW fans operable per train. SNC has a replacement gearbox on site and work to install it is in progress. However, gearbox replacement involves several major activities, and the outdoor location and relative inaccessibility of the gearbox atop the NSCW cooling tower add complexity to this task.

Steps involved in gearbox replacement include:

1. Positioning a crane alongside the 1 B NSCW cooling tower
2. Building a temporary access structure in the #3 cooling tower cell
3. Uncoupling, unbolting and removing the old gearbox/fan assembly
4. Swapping the fan hub and blades over to the new gearbox
5. Installation and alignment of the new gearbox/fan assembly
6. Removal of the temporary access structure
7. Functional testing and return to service Completion of these activities is anticipated to require more than the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowable outage time (which will expire at 0834 hours0.00965 days <br />0.232 hours <br />0.00138 weeks <br />3.17337e-4 months <br /> on August 6, 2010),

necessitating request of this one-time emergency TS amendment.

3.0 Need for Technical Specification Change The proposed one-time change to the VEGP Unit 1 Completion Time of TS 3.7.9, Condition B, is needed to avoid the unnecessary shutdown of the plant due to the additional time required to complete Unit 1 Train B NSCW cooling tower fan #3 gearbox replacement. A risk assessment has been performed which shows that the incremental risk for the proposed change is acceptable. The alternative of shutting down VEGP Unit 1 for a low risk condition that would reduce the available margin for grid electrical reserve during the current high demand summer period with little corresponding safety benefit.

Page 1 of 27

Enclosure 1 Description of the Proposed Change 4.0 Description of Proposed Change 4.1 Proposed Change Add a note to allow a one-time change to TS LCO 3.7.9 Condition B Completion Time to extend it from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days.

4.2 System Description

The Ultimate Heat Sink (UHS) provides a heat sink for processing and operating heat from safety related components during a transient or accident, as well as during normal operation. This is done by utilizing the Nuclear Service Cooling Water (NSCW) System and the Component Cooling Water (CCW) System.

The UHS consists of the NSCW System mechanical draft towers. Two 100%

capacity redundant NSCW towers are provided for each unit. One tower is associated with each train of the NSCW System. Each NSCW tower consists of a basin that contains the ultimate heat sink water supply and an upper structure that contains four individual fan spray cells where the heat loads are transferred to the atmosphere. Each spray cell contains one safety-related temperature controlled fan. Instrumentation is provided for monitoring basin level and water temperature. The tower basins each contain a safety-related transfer pump to permit the use of the combined storage capacity of the basins. The combined storage capacity of two tower basins provides greater than a 30 day cooling water supply assuming the worst combination of meteorological conditions and accident heat loads which maximize the tower heat load, basin temperature, and evaporative losses.

4.3 Basis for the Technical Specification Change TS 3.7.9, "Ultimate Heat Sink (UHS)," requires that the UHS be OPERABLE in MODES 1, 2, 3, and 4.

The UHS is considered OPERABLE if it contains a sufficient volume of water at or below the maximum temperature that would allow the NSCW to operate for at least 30 days following the design basis LOCA without the loss of net positive suction head (NPSH), and without exceeding the maximum design temperature of the equipment served by the NSCW.

In order to meet these requirements, two NSCW tower basins are required OPERABLE with the following:

1. Basin water level must be ->80.25 feet as measured from the bottom of the basin (73% of instrument span),
2. Basin water temperature must be - 900 F, Page 2 of 27

Enclosure 1 Description of the Proposed Change

3. Two OPERABLE trains of NSCW tower fans, each train consisting of four fans and four spray cells when ambient wet-bulb temperature > 630 F or three fans and four spray cells (sprays and natural draft through the nonoperating fan) when ambient wet-bulb temperature < 630 F, and
4. Two OPERABLE NSCW basin transfer pumps.

Requirements 1 and 4 above are unaffected by the proposed TS change.

Requirement 2, for basin water temperature < 900 F, is not expected to be challenged (it is presently < 820F with three fans in service) but will be closely monitored during the extended Completion Time period to ensure continued compliance.

Requirement 3 above is the subject of this proposed one-time change to extend the Unit 1 Completion Time of TS 3.7.9, Condition B, to allow one inoperable NSCW cooling tower fan (with three fans remaining in service) for up to 7 days. A probabilistic risk assessment (see Section 5.0 below) has shown this Completion Time extension to have a minimal impact on plant risk.

Moreover, as discussed in the VEGP Units 1 & 2 Final Safety Analysis Report (FSAR) Section 9.2.5 description of the Ultimate Heat Sink, the governing case for the maximum basin temperature and NSCW outlet temperature from the fan coolers is one-train continuous operation post-LOCA. In this case, the most limiting single active failure (loss of one complete NSCW train) is assumed, plus loss of one fan in the operable tower as a result of a missile strike. The remaining three fans in the operating train will then maintain the temperature in the tower basin below 90 0 F, thus the ability to maintain hot standby under such conditions is provided.

Consideration of a missile strike is not required because the LCO time limit prohibits extended operation with three fans.

Review of maintenance history for the NSCW cooling tower fans identified just 5 previous gearbox replacements (3 in Unit 1, 2 in Unit 2) among the 8 fans per unit in over 21 years of operation since initial startup. These replacements were on the first-starting (hence longest run time) fan in each tower, plus one second-starting fan. Unit 1 Train B has had one previous fan gearbox replacement, in September 2000. Fan gearbox problems requiring replacement are thus seen as rare events, with the 1 B #3 fan (third-starting) gearbox problem an apparent anomaly not indicative of a common-cause problem which would reduce confidence that the three other 1B fans will operate reliably during the proposed extended TS 3.7.9 Condition B Completion Time period.

Compensatory Measures Compensatory measures will be implemented during the extended Completion Time period required for repair of 1B NSCW cooling tower fan #3, including designation of both trains of safety related equipment as "Protected Trains."

Page 3 of 27

Enclosure 1 Description of the Proposed Change Nuclear management procedure NMP-OS-010 defines the "Protected Train and Protected Equipment" concept. The fundamental objective of the procedure is to enhance nuclear safety by ensuring continued availability of equipment necessary to maintain plant emergency response capability and prevent inadvertent plant trips, transients, or safety system challenges. This procedure provides guidance for management of the protected train and for posting protected equipment when redundant equipment is out of service.

Additionally, operation or maintenance of protected plant equipment is limited or prohibited.

To maintain plant personnel awareness of the protected train, at a minimum, the protected train is identified on the plant morning report, in the Main Control Room, Maintenance Shop areas, HP Control Point and in the Work Release office. The protected train is also discussed at the beginning of shift briefings for each group.

Activities such as corrective and preventative maintenance, system or component testing or activities where human error could result in damage to or loss of protected equipment (e.g. erecting scaffolding in the vicinity) are prohibited unless authorized by the operations Shift Manager or Operations management.

In addition to the measures outlined above, signage has been posted on several key components associated with A train NSCW (e.g. A train NSCW fan handswitches, A train NSCW fan switchgear room, A train 4160kV switchgear room) to alert personnel to the fact that the equipment is part of the protected train.

Also included in the compensatory measures:

- No Unit 1 high voltage or Unit 1 low voltage switchyard work will be performed

- The Emergency Diesel Generators will be maintained available

- The Turbine Driven AFW Pump will be maintained available (note that a scheduled surveillance test will be run on Motor Driven AFW Pump 1A)

- Enhanced Operator rounds will be performed for A train equipment Defense in depth is provided based on the number of fans (4) versus the number of fans assumed in the FSAR safety analyses (3 worst case). In addition, the compensatory measures discussed above provide additional defense in depth.

5.0 Risk Assessment A probabilistic risk assessment (PRA) has been performed using the NRC's three-tier approach described in RG 1.177. The three tiers consist of:

Page 4 of 27

Enclosure 1 Description of the Proposed Change Tier 1 - PRA Capability and Insights Tier 2 - Avoidance of Risk-Significant Plant Configurations, and Tier 3 - Risk-Informed Configuration Risk Management Tier 1: PRA Capability and Insights PRA Capability SNC employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all operating SNC nuclear generation sites. This approach includes both a proceduralized PRA maintenance and update process, and the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the VEGP PRA.

Technical Adequacy of VEGP PRA Model The SNC risk management process ensures that the applicable PRA model remains an accurate reflection of the as-built and as-operated units. The SNC risk management process also delineates the responsibilities and guidelines for updating the full power internal events PRA models at all operating SNC nuclear generation sites. The overall SNC risk management program defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, industry operational experience), and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plant, the VEGP PRA model has been updated according to the requirements defined in the SNC risk management process:

" Pertinent modifications to the physical plant (i.e. those potentially affecting the Base Line PRA (BL-PRA) models, calculated core damage frequencies (CDFs), or large early release frequencies (LERFs) to a significant degree) shall be reviewed to determine the scope and necessity of a revision to the baseline model within six months following the Unit 2 refueling outage or a specific major plant modification occurring outside a refueling outage. The BL-PRAs should be updated as necessary in accordance with a schedule approved by the PRA Manager following the scoping review. Upon completion of the lead Unit's BL-PRA, the other Unit's BL-PRA will be regenerated by modification of the updated BL-PRAs to account-for Unit differences which significantly impact the results.

" Pertinent modifications to plant procedures and Technical Specifications shall be reviewed annually for changes which are of statistical significance to the results of the BL-PRA and those changes documented. Reliability data, failure data, initiating events frequency data, human reliability data, and other such PRA inputs shall be reviewed approximately every three years for statistical significance to the results of the BL-PRAs. Following the tri-annual review, the BL-PRAs shall be Page 5 of 27

Enclosure 1 Description of the Proposed Change updated to account for the statistically significant changes to these two categories of PRA inputs in accordance with an approved schedule.

  • BL-PRAs shall be updated to reflect germane changes in methodology, phenomenology, and regulation as judged to be prudent by the PRA custodian or as required by regulation.

In addition to these activities, SNC risk management procedures provide the guidance for particular risk management and PRA quality and maintenance activities. This guidance includes:

" Documentation of the PRA model, PRA products, and bases documents.

" The approach for controlling electronic storage of Risk Management (RM) products including PRA update information, PRA models, and PRA applications.

" Guidelines for updating the full power, internal events PRA models for SNC nuclear generation sites.

" Guidance for use of quantitative and qualitative risk models in support of the On-Line Work Control Process Program for risk evaluations for maintenance tasks (corrective maintenance, preventive maintenance, minor maintenance, surveillance tests and modifications) on systems, structures, and components (SSCs) within the scope of the Maintenance Rule (10 CFR 50.65 (a)(4)).

In accordance with this guidance, regularly scheduled PRA model updates nominally occur on an approximate three year cycle; however, longer intervals may be justified if it can be shown that the PRA continues to adequately represent the as-built, as-operated plant. Table 1 shows the brief history of the major VEGP PRA model updates.

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Enclosure 1 Description of the Proposed Change Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

IPE WCAP-13553 At-power, internal The original CDF: 4.9E-5 (Westinghouse and external, CDF LERF: 1.78E-6 report) by and Level 2 PRA Westinghouse and SNC, 11/1992 Rev. 0 SAIC prepared At-power, internal, Conversion from a large Event CDF: 3.62E-5 reports, 3/1998. CDF and LERF Tree/small Fault Tree approach LERF: 1.72E-6 to a small Event Tree/large Fault Tree approach (linked fault tree The CDF reduction was mainly due to model method). changes, such as, removal of unrealistic SBO scenarios, addition of more realistic PRA software change from assumptions regarding the effect of loss of WESQT/GRAFTER room cooling, and removal of a (Westinghouse Event Tree and 'guaranteed failure' assumption made Fault tree software) to CAFTA. during IPE for event CON (operator action to depressurize one SG to cause feed flow from the condensate pumps if AFW failed).

Rev. 1 PSA-V-99-002 At-power, internal, Enhanced the treatment of CDF: 3.702E-5 by SNC, 9/1999 CDF and LERF operator action dependency, LERF: 2.290E-6 removal of circular logic, and minor corrections/

improvements.

Page 7 of 27

Enclosure 1 Description of the Proposed Change Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

Rev. 2 PSA-V-99-012 At-power, internal, Update of initiating event CDF: 1.48E-5 by SNC, 1/2000 CDF and LERF frequencies, component failure LERF:1.15E-6 data, and maintenance unavailablities using plant There was a considerable reduction in specific data collected though CDF mainly due to reduction in the the end of 1998. transient event frequency. The sum of frequencies of eight transient Incorporated plant changes. subcategories was reduced from 4.04/yr to 2.64/yr after the data update. Also, items updated during revision Oa, Ob, and Oc, especially the crediting of the plant Wilson switchyard for a back up AC power source, contributed to the reduction in CDF.

The reduction in LERF was mainly due to reduced failure probabilities of some of the components, especially NSCW pumps, which have a significant contribution to the LERF after the Bayesian update of failure data using VEGP specific failure data.

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Enclosure 1 Description of the Proposed Change Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

Rev. 2a PSA-V-00-003 At-power, internal, Addition of RCP seal LOCA CDF = 2.40E-5, by SNC, 7/2000 CDF and LERF failure modes which were newly LERF = 7.34E-7 identified by the Westinghouse Owners Group (WOG), changes CDF increase was due to new RCP seal in success criteria for Steam LOCA failure modes.

Generator Tube Rupture LERF decrease due to changes in success (SGTR), and minor changes to criteria for SGTR facilitate Maintenance Rule and MOV/AOV risk ranking.

Rev. 2b PSA-V-00-020 At-power, internal, Minor improvement in recovery CDF = 2.38E-5 by SNC, 11/2000 CDF and LERF tree for recovery analysis. LERF = 7.34E-7 No significant changes in CDF and LERF Rev. 2c PSA-V-00-030 At-power, internal, Peer reviewed model by the WOG CDF: 1.602E-5, by SNC, 11/2001 CDF and LERF PRA peer review team. LERF:7.802E-8 Revised the LERF model based on The CDF decrease was mainly due to a the new WOG LERF modeling decrease in LOCA frequencies after an guidelines. Updated the initiating update of initiating frequencies using event frequencies using the more NUREG/CR-5750 data.

recent generic data source (NUREG/CR-5750). The decrease in LERF was due to the removal of some SGTR scenarios from the Some SGTR scenarios were LERF model.

removed from the LERF scenarios and minor changes were made to facilitate RISB analysis. Removed circular logic in normal charging pump fault trees.

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Enclosure 1 Description of the Proposed Change Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

Rev. 3 PRA-BC-V At-power, internal, This is the most extensive upgrade CDF: 1.28E-5 001, by SNC, CDF and LERF of the VEGP PRA model since the LERF: 1.10E-7 2/2006 IPE.

The CDF changes were due to combined

  • All level 1 PRA tasks, from the effects of many changes during revision 3.

selection and grouping of initiating events to the final The main cause of the LERF increase was quantification were practically the regrouping of all of the SGTR re-done. sequences back into the containment bypass scenarios, and the removal of the

  • Resolved all Westinghouse credit for mitigating systems for some Owners Group PRA peer review Interfacing Systems LOCA scenarios (as B Facts & Observations (F&Os). resolutions of peer review findings).

There were no A F&O for VEGP. I Page 10 of 27

Enclosure 1 Description of the Proposed Change Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

VEGPL2UP P0293060001- At-power, internal, Based on the Rev.3 level 1 PRA CDF: 1.552E-5 model 2707 CDF and full level logic. This model was used for the 1.529E-5 (after treating success (ERIN report) by 2 Severe Accident Management terms)

SNC and ERIN, Alternative Analysis for the VEGP LERF: 1.819E-7 11/2006 license renewal which was submitted in 2007. The increase in CDF (before treating success terms) from revision 3 to Upgraded the full Level 2 PRA VEGPL2UP model was due to the model, based on WCAP-16341-P correction of a RCP seal LOCA probability guidelines which aim for producing from WCAP-16141.

an ASME PRA capability category II LERF model. The above LERF value is the sum of four LERF release categories: LERF-BYPASS, Incorporated success terms in level LERF-ISO, LERF-CFE, and LERF-SGTR.

1 and level 2 logic. Corrected an error in the level 1 PRA failure data.

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Enclosure 1 Description of the Proposed Change Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

Rev. 4 PRA-BC-V At power, internal, The following items are complete: CDF: mean = 1.40E-5/yr, error factor =

003 CDF and full level 1.8 2

  • Closed all gaps identified from a LERF: mean = 4.96E-8, error factor = 3.1 The original was self assessment.

prepared in April 2009 for R.G ° Re-performed pre-initiator HFE LERF reduction was due to correct a 1.200 R1 peer screening for gap closure. wrong Steam generator tube condition review against used in the previous model. SG tube ASME PRA ° Update of initiating frequency condition affects the probabilities of standard in May and component failure data induced SGTR. Based on the current 2009. using new plant experiences and VEGP SG tube plugging rate, which is less new generic failure data base than 2.5%, the current VEGP SG tube Rev.4 model will (NUREG/CR-6928). condition is "pristine", instead of "average" be re-issued in as assumed in the previous model (ref:

the first half of

  • Re-performed internal flooding WCAP-16341-P). Also, by use of new 2010 after PRA. generic initiating event frequency, medium resolving all "SR LOCA contributions increased significantly Not met" Finding ° Update of system notebooks. because the revised medium LOCA and frequency based on new generic data Observations ° Uncertainty analysis considering base (NUREG/CR-6928) is almost an (total three). the state of knowledge order of magnitude higher than previous correlation. generic value.

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Enclosure 1 Description of the Proposed Change Consistency with Applicable ASME PRA Standard Requirements Previous peer review and Self Assessment for VEGP PRA Model In addition to independent internal and external review during each VEGP PRA model development and update, several assessments of the technical capability have been made before the PWR Owners Group (PWROG) peer review against ASME PRA Standard and R.G. 1.200, Revision 1 in May of 2009. Listed below are the previous assessments for VEGP PRA:

An independent PRA peer review was conducted under the auspices of the Westinghouse Owners Group (WOG) in December 2001, following the Industry PRA Peer Review process (Reference 1). This peer review included an assessment of the PRA model maintenance and an update process. This assessment did not identify any "A" Facts & Observations (F&Os). All "B" F&Os from the 2001 Industry PRA Peer Review for VEGP PRA were addressed in VEGP PRA model Revision 3.

" During 2005, the VEGP PRA model results were evaluated in the WOG PRA cross-comparisons study performed in support of implementation of the mitigating systems performance indicator (MSPI) process. Results of this cross-comparison are presented in WCAP-16464, Westinghouse Owner's Group Mitigating Systems Performance Index Cross Comparison. The PRA Cross comparison Candidate Outlier Status was described in section 3.4 of VEGP MSPI base document. Noted in this document was the fact that, after allowing for plant-specific features, there are no MSPI cross-comparison outliers for VEGP PRA.

" In 2006, a gap analysis was performed against the available versions of the ASME PRA Standard (Reference 2) and Regulatory Guide 1.200, Revision 0 (2003 trial version).

" In 2008, VEGP PRA model (draft Revision 4) was benchmarked with three Westinghouse PWRs (Comanche peak, Callaway, Wolf Creek) as a part of MSPI margin study. The benchmarking concluded that there were no significant issues in the VEGP PRA model which would impact MSPI calculations RG 1.200 PRA Peer Review for VEGP PRA Model against ASME PRA Standard Requirements The VEGP PRA model for internal events (including internal flooding) at power was updated to Revision 4 early in 2009 to close the gaps from the 2006 self assessment, to meet the ASME PRA standard'supporting requirements, and to represent as-built as-operated plant.

In May of 2009, the VEGP PRA model Revision 4 was reviewed per RG 1.200 Revision 1 (Reference 3) against ASME PRA Standard Requirements (Reference 4). A summary of this peer review is provided below:

Page 13 of 27

Enclosure 1 Description of the Proposed Change The ASME PRA Standard (Reference 4) contains a total of 327 numbered supporting requirements (SRs) in nine technical elements and the configuration control element. Eleven of the SRs represent deleted requirements (IE-A8, IE-A9, SC-A3, SY-A9, SY-B9, HR-G8, IF-A2, IF-B4, IF-D2, IF-E2, and QU-D2) and 20 were determined to be not applicable to the VEGP PRA. Among 296 applicable SRs, 99% of SRs met Capability Category II or higher as follows:

Capability Category Met No. of SRs  % of total applicable SRs CC-I/Il/Ill (or SR 210 70.9%

Met)

CCI 0 0%

CC II 38 12.8%

CC III 7 2.4%

CC 1/11 14 4.7%

CC 1I/111 24 8.1%

SR Not Met 3 1.0%

SR (CC-I/I I/Il) Met 296 100 Three SRs were judged to be not met. These are HR-G6, QU-D3, and LE-G5. HR-G6 was not met because the reasonableness check of Human Reliability Analyses (HRA) was done for the previous revision of the PRA and not the latest revision. QU-D3 was not met because the SR requires the PRA results to be compared with those from similar plants. The VEGP PRA report cites the MSPI benchmark report as evidence of meeting this requirement, which is an outdated comparison. SR LE-G5 was characterized as "Not Met" because the limitation of the LERF calculations that could impact risk-informed applications was not identified Resolution of Findings from RG 1.200 PRA Peer Review Table 2 shows details of the three "SR Not Met" findings and resolutions after the peer review. As shown in Table 2, the three not met SRs have been resolved.

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Enclosure 1 Description of the Proposed Change Table 2 Resolution of the VEGP PRA Peer Review F&Os associated three "SR not Met" SRs F&O # Review Level' Resolution The Status of Resolution by SNC Element HR-G6-01 HR-G6 Finding Check of consistency and review for Reasonableness check for all HRAs for (SR not met reasonableness is missing in the Revision 4 Revision 4 model was re-performed. All CC-I/II/Ill) updated HRA draft and the prior revision HRAs have been determined to be document information related to these items is reasonable or have been appropriately not appropriate to use in light of the updates revised.

performed and changes to the results. Section 8 includes a table of HFEs and HEPs but does not include HEP reasonableness check, as is documented in Section 8.3 of the November 2005 HRA update for Revision 3.

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Enclosure 1 Description of the Proposed Change Table 2 Resolution of the VEGP PRA Peer Review F&Os associated three "SR not Met" SRs F&O # Review Level' Resolution The Status of Resolution by SNC Element QU-D3-01 QU-D3 Finding Reviewer asked the VEGP Staff to provide In order to resolve this F&O, a new (SR CC-Il Not evidence of comparison of the VEGP results to comparison study was performed by met) those from similar plants. The VEGP staff comparing VEGP PRA results with two presented the benchmark report for MSPI as PWR PRAs (Callaway and Wolf Creek) evidence of comparison. Reviewers concluded which are considered relatively similar to that report is not sufficient evidence for VEGP. In addition to the comparison of demonstrating compliance to this SR. PRA reports, a plant visit to Callaway was performed to identify more details of Callaway systems and PRA modeling.

The comparison showed that all three plants have LOSP/Station black out as the most dominant contributors which indicated that the VEGP PRA results are not an outlier as compared to similar PWRs. Differences in dominant CDF contributors were investigated and it was found that those differences are due to differences in details of system configuration/operation and physical barriers for internal flooding, and in the sources for generic initiating event frequency data (VEGP PRA used the latest generic initiating frequency and failure data along with VEGP specific experience data for its data update).

Therefore, this F&O has been resolved.

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Enclosure 1 Description of the Proposed Change Table 2 Resolution of the VEGP PRA Peer Review F&Os associated three "SR not Met" SRs F&O # Review Level' Resolution The Status of Resolution by SNC Element LE-G5-01 LE-G5 Finding Limitations in the LERF analysis that would A comparison of Vogtle LERF scenarios (SR Not met impact applications are not identified. LERF with those in Table 4.5.9.3 of the ASME CC 1/11/111) analysis documentation is incomplete because PRA standard revealed that the Vogtle limitations in the LERF analysis that would PRA included more potential LERF impact applications, as required by SR LE-G5, scenarios than as required for a large dry are not identified. containment plant in ASME PRA standard.

The LERF scenarios modeled in VEGP PRA include containment bypass core damage scenarios (steam generator tube rupture and Interfacing systems LOCA),

thermally or pressure induced steam generator tube rupture after core damage, containment isolation failure with core damage, and various early containment failure modes.

Therefore, this F&O has been resolved.

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Enclosure 1 Description of the Proposed Change External Event Considerations In the absence of quantifiable PRA models for all external hazards, a qualitative or bounding analysis is performed to provide justification for the acceptability of this proposed change.

External hazards were evaluated in the VEGP Individual Plant Examination of External Events (IPEEE) submitted in response to the NRC IPEEE program (Generic Letter 88-20, Supplement 4) (Reference 5). The IPEEE program was a one-time review of external hazard risk and was limited in its purpose to the identification of potential plant vulnerabilities and the understanding of associated severe accident risks. The results of the VEGP IPEEE study are documented in the VEGP IPEEE main report. The primary areas of external event evaluation at VEGP were internal fire and seismic.

External Event Risk The Individual Plant Examination of External Events (IPEEE) was performed as a onetime assessment of the impact of external events and is not periodically updated. SNC is developing a state-of-the-art fire PRA model but it is not yet ready to support detailed risk calculations required for this emergent LAR. Also, a full update of the IPEEE fire PRA model to incorporate changes in methodology and plant modification would be manpower intensive. Therefore, the IPEEE results are used to obtain a bounding estimate of the risk increase due to the unavailability of the NSCW fan.

- Fire Hazard Based on a review of the IPEEE report and its supporting evaluations, the total fire core damage risk was estimated as 1.01 E-5 per year. This represented about 22.7 percent of the core damage risk from the internal events hazards. Also, based on a review of the results, it was noted that the fire risk contribution from 9 fire zones accounts for more than 60 percent of.

the total fire risk for Unit 1. It was also noted that 4 out of the 9 fire zones were train B related fire zones. The unavailability of a NSCW fan #3, which is powered from Train B of the emergency power, has no impact on the fire risk contribution of train B related fire areas because a fire in the B train related zones (e.g., 1-CB-LA-I-88-L-R2) is assessed to result in a loss of either NSCW train B or train B 4kV Switchgear. Finally, it was also noted that the "most significant nonfire failures" in the train A related fire zones, are DG B failures.

Based on the above observations, it is concluded that the fire risk hazard does not have significant impact on the proposed extension to the NSCW tower fan on the following basis:

  • The total fire risk is significantly lower than the internal events risk (about 22.7%)

and addition of the fire risk to the internal events risk is not expected to increase the total CDF above 1 E-04/yr. As a result ACDF within Region II and III of Figure 3 of RG 1.174 are considered acceptable. For this particular application the total ACDF estimate is expected to fall within Region III (it is expected to fall within 1 E-06)

  • The contribution of unavailability of the fan to the fire risk is insignificant because:

- There is adequate redundancy. The success criteria for NSCW cooling tower fan is one of 4 for non-LOCA events. Most fires events (higher frequency Page 18 of 27

Enclosure 1 Description of the Proposed Change events) do no result in LOCAs. Even in case of lower frequency events such a fire-induced stuck open PORVs, the PRA success criteria of 3 out of 4 fans is met even with fan #3 being OOS.

- The contribution of some of the most risk significant fire scenarios is not affected.

As stated about 4 out of the 9 fire risk significant zones are the train B related zone. The unavailability of the fan will not have an impact on the risk contribution from fires in such zones because the a fire in such areas will result in a loss of power to the fan

- The contribution from the remaining fire risk significant zones is not significantly impacted. Again, as stated above, the "most significant nonfire failures" in the train A related fire zones, are DG B failures. Fire-induced non LOCA events are major contributors where random failure of DG B will be risk significant. For such scenarios (non-LOCA loss of offsite power), only 1 of 4 fans is required to keep EDG operable. As a result, unavailability of one fan will have a minimal impact on the failure probability of the DG B.

Therefore, based on the above evaluation and the short duration of the proposed extension in the completion time, it is concluded that the inoperable status of the NSCW fan #3 would not result in any significant change to the base case core damage contribution from fire risk.

- Seismic Hazard The Vogtle plant has been designed to accommodate a safe-shutdown earthquake (SSE) with 0.2g peak ground acceleration (pga). However, due to conservatisms applied to the demand and/or evaluation techniques, most of the Seismic Category I structures and equipment were designed and qualified for a 0.3g pga capacity. The seismic analysis performed in the IPEEE study is intended to act as a performance check on the design, estimating seismic capacity beyond the SSE. The seismic analysis methodology implemented for Vogtle satisfied the NRC requirements for performing a seismic IPEEE as presented in Generic Letter 88-20, Supplement 4. Seismic events were evaluated using the Seismic Margins Analysis (SMA) method. The SMA methodology uses a deterministic approach to identify the weakest components in terms of High Confidence Low Probability of Failure (HCLPF) during peak ground acceleration. A seismic margin can be expressed in terms of the earthquake motion level that compromises plant safety; the seismic margin assessment determines whether there is high confidence that the plant can survive a given earthquake. No core damage frequency sequences were quantified as part of the IPEEE seismic risk analysis. The seismic margin analysis results showed that the contribution of this hazard to the total risk is insignificant. Additionally, it is judged that the proposed increase in the unavailability of the NSCW fan #3 has an insignificant (well below 1.OE-6 per year) impact on the seismic risk because a seismic event severe enough to result in a failure of a NSCW fan would also result in failure of the redundant fans.

For seismic events of larger magnitudes, equipment on both trains is assumed to fail. In the case of lower level earthquakes an LOSP is assumed to occur. The LOSP IE frequency in the internal events PRA considers LOSP events initiated by seismic events. Therefore the contribution to increase in total CDF (of NSCW of cooling tower fan #3 0OS) due to a seismic event is included in the internal events results and has been shown to be insignificant.

Based on the above evaluation and the short duration of the proposed extension in the completion time, it is concluded that the inoperable status of the NSCW fan #3 would not Page 19 of 27

Enclosure 1 Description of the Proposed Change result in any significant change to the base case core damage contribution from seismic hazard.

- Other External Hazards In addition to internal fires and seismic events, the VEGP IPEEE analysis of high winds, floods, and other (HFO) external hazards was accomplished by using a progressive screening approach described in NUREG-1407. The VEGP IPEEE concluded that the existing VEGP design was in conformance with the 1975 Standard Review Plan (SRP),

NUREG-75-087, criteria, in all reviewed areas and no potential vulnerabilities were identified. HFO events were screened out by compliance with the SRP. As such these hazards were determined to be negligible contributors to the overall plant risk.

General Conclusion Regarding PRA Capability The VEGP PRA maintenance and update processes and technical capability evaluations described above provide a robust basis for concluding that the PRA is suitable for use in risk-informed licensing actions. As specific risk-informed PRA applications are performed, remaining gaps to specific requirements in the PRA standard will be reviewed to determine application specific additional analysis, i.e., sensitivity studies, which may be required on an as needed basis.

Risk Evaluation Methodology The approach used in the assessment of the increase in risk included the following considerations:

1) potential for creating a new initiating event (IE),
2) potential for an increase in the frequency of an existing IE(s),
3) and impact on the consequence of an IE.

New IE Based on a review of the pertinent PRA calculation file, it is judged that that an inoperable NSCW fan would not introduce a new IE.

Impact on the Frequency of an Existing IE Loss of NSCW due to the loss of running NSCW pumps and the failure to start of standby pumps is modeled as an initiating event in the Vogtle PRA. Again, based on a review of the pertinent PRA calculation file, it is judged that an inoperable NSCW cooling tower fan has minimal impact on the frequency of an existing IE. Loss of an NSCW cooling tower is not modeled as an initiating event in the Vogtle PRA is because if the cooling tower fails to provide cooling there is a time delay before the water in the cooling tower would heat up to an unacceptable temperature for continued operation of NSCW.

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Enclosure 1 Description of the Proposed Change Impact on Consequences An inoperable NSCW cooling tower fan would reduce the capability of the ultimate heat sink. The impact of the above-induced reduction of the ultimate heat capability on risk is evaluated and quantified as follows:

Risk Metrics ACDFAVE = change in the annual average CDF due to increased unavailability of the NSCW cooling tower fan #3 that could result from the increased Completion Time (CT).

This risk metric is compared against the criteria of RG 1.174 to determine whether a change in CDF is regarded as risk significant. These criteria are a function of the baseline annual average core damage frequency, CDFBASE.

ALERFAVE = change in the annual average LERF due to the increased unavailability of the NSCW cooling tower fan #3 that could result from the increased CT. Similar to ACDFAVE, RG 1.174 criteria were also applied to judge the significance of changes in this risk metric.

ICCDP = incremental conditional core damage probability with the NSCW cooling tower fan #3 out of service for an interval of time equal to the proposed CT (i.e., 7 days). This risk metric is used as suggested in RG 1.177 to determine whether a proposed CT has an acceptable risk impact.

ICLERP = incremental conditional large early release probability with the NSCW cooling tower fan #3 out of service for an interval of time equal to the proposed CT. Similar to ICCDP, RG 1.177 criteria were also applied to judge the significance of changes in this risk metric.

Since this is a one-time increase in the completion time for one NSCW cooling tower fan, the change in average risk is considered to be negligible. The ICCDP and ILERP risk metrics were quantified using the equations provided below.

Incremental Conditional Probabilities The incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP) are computed using their definitions in RG 1.177.

The ICCDP values are dimensionless probabilities used to evaluate the incremental probability of a core damage event over a period of time equal to the extended CT. This should not be confused with the evaluation of ACDFAVE, in which the CDF is based on expected unavailability. However, the endstate frequencies used to calculate ICCDP/ICLERP are the same as those used to calculate the change in CDF/LERF as described in the previous section.

The ICCDP is calculated by multiplying the change in CDF by the proposed TS CT.

Therefore, ICCDP = (CDFoos - CDFBAsE )x CT (Equation 1)

Similarly, ICLERP is defined as follows.

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Enclosure 1 Description of the Proposed Change ICLERP = (LERFoos - LERFBASE )x CT (Equation 2) where CT is the proposed TS CT (i.e., 7 days).

Results And Conclusion The results of the risk evaluation (Enclosure 2, RBA 10-011 -V) are presented in Tables 3 and 4. These tables show the results of the risk metric calculations. The total base CDF

("Base Model") value is approximately 1.1350 E-05/yr. Total base LERF is approximately 3.8163 E-08/yr. The total base CDF and LERF values include contributions from internal, seismic and fire events.

Tables 3 and 4 shows the results of this evaluation.

Table 3 ICCDP Results Incremental CDF Fan #3 CDF Fan #3 CDF Fan #3 Conditional Core OOS Internal OOS Fire OOS Seismic CDF Base Case Damage Events Probability ICCDP 1.1438 E-05 - 1.1 350 E-05 1.6877E-09 Internal Events only contribution from NSCW tower fan #4 00S for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and AFW MDP A OOS for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> during the 7 day 7.0448E-09 period that NSCW tower fan #3 is OOS TOTAL 8.7325E-09 Table 4 ICLERP Results Incremental LERF Fan #3 LERF Fan #3 CDF Fan #3 Conditional Large OOS Internal OOS Fire oOS Seismic LERF Base Case Early Release Events Probability ICCDP 3.8268E-08 - 3.8163E-08 2.0137E-12 Internal Events only contribution from NSCW tower fan #4 00S for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and AFW MDP A OOS for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> during the 7 day 3.9479E-10 period that NSCW tower fan #3 is OOS TOTAL 3.9681E-10 The results of the risk evaluation are compared in Table 5 with the risk significance criteria from RG 1.177 for ICCDP and ICLERP.

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Enclosure 1 Description of the Proposed Change

" The change in these figure of merits are much less than the criteria for these metrics. Therefore, margins to the change in these figures of merit demonstrate that the criteria are met with sufficient margin.

" The calculated values for ICCDP and ICLERP demonstrate that the proposed NSCW cooling tower fan #3 Completion Time change has only a small quantitative impact on plant risk, as they are less than the Regulatory Guide acceptance criteria.

Table 5 Results of Risk Evaluation for Unit 1 Risk Risk Risk Metric Results Significance (% of Risk Significance Criterion)

METRIC Criterion Unit 1 ICCDP < 5.OE-07 8.7325E-09 (1.7%)

ICLERP < 5.OE-08 3.9681E-10 1_ 1 (0.8%)

Tier 2: Avoidance of Risk-Significant Plant Configurations The objective of the second tier, which is applicable to CT extensions, is to provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when equipment is out of service. If risk-significant configurations do occur, then enhancements to TSs or procedures, such as limiting unavailability of backup systems, increased surveillance frequencies, or upgrading procedures or training, can be made that avoid, limit, or lessen the importance of these configurations.

The potential configurations that should be avoided while the NSCW cooling tower fan #3 is out of service are identified from a review of the cutsets generated for this condition using the base case PRA model (Enclosure 2, RBA 10-011 -V):

The dominant contributors to risk with NSCW cooling tower fan #3 out of service are related to failures of other NSCW equipment such as the other cooling tower fans, failure of the NSCW cooling tower return MOVs, or failure of NSCW pumps.

Adhering to the current risk management program in combination with our current TS requirements and procedures will prevent these types of risk-significant configurations from occurring. Therefore, there is reasonable assurance that risk-significant plant equipment configurations will not occur while the NSCW cooling tower fan #3 is OOS using the proposed TS changes. No other changes to the TSs or procedures, or any compensatory actions, are required as the result of this proposed License Amendment Request (LAR).

Tier 3: Risk-Informed Configuration Risk Management The objective of the third tier is to ensure that the risk impact of out-of-service equipment is evaluated prior to performing any maintenance activity. As stated in Page 23 of 27

Enclosure 1 Description of the Proposed Change RG 1.177, "a viable program would be one that is able to uncover risk-significant plant equipment outage configurations as they evolve during real-time, normal plant operation." The third-tier requirement is an extension of the second-tier requirement, but addresses the limitation of not being able to identify all possible risk-significant plant configurations in the second-tier evaluation.

SNC has developed a process for online risk assessment and management.

Following the process and procedures ensures that the risk impact of equipment unavailability is appropriately evaluated prior to performing any maintenance activity, or following an equipment failure or other internal or external event that impacts risk. Nuclear management procedure NMP-OS-010, "Protected Train/Division and Protected Equipment Program," provides guidance for managing safety function, probabilistic, and plant trip risks as required by 10 CFR 50.65(a)(4) of the Maintenance Rule. The procedure addresses risk management practices in the maintenance planning phase and maintenance execution (real time) phase for Modes 1 through 4. Appropriate consideration is given to equipment unavailability, operational activities such as testing, and weather conditions.

In general, risk from performing maintenance on-line is minimized by:

  • Performing only those preventive and corrective maintenance items on-line required to maintain the reliability of systems, structures or components (SSC)s.
  • Minimizing cumulative unavailability of safety-related and risk-significant SSCs by limiting the number of at-power maintenance outage windows per cycle per train/component.
  • Minimizing the total number of SSCs out of service at the same time.
  • Minimizing the risk of initiating plant transients (trips) that could challenge safety systems by implementing compensatory measures.

" Avoiding higher risk combinations of out of service SSCs using PRA insights.

  • Maintaining defense-in-depth by avoiding combinations of out of service SSCs that are related to similar safety functions or that affect multiple safety functions.
  • Scheduling in train/bus windows to avoid removing equipment from different trains simultaneously.

In general, risk is managed by:

  • Evaluating plant trip risk activities or conditions and mitigating them by taking appropriate compensatory measures and/or ensuring defense-in-depth of safety systems that are challenged by a plant trip.
  • Evaluating and controlling risk based on probabilistic and key safety function defense-in-depth evaluations.
  • Implementing compensatory measures and requirements for management authorization or notification for certain "high-risk" configurations.

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Enclosure 1 Description of the Proposed Change Actions are taken and appropriate attention is given to configurations and situations commensurate with the level of risk as evaluated using AD7.DC6. This occurs both during planning and real time (execution) phases.

For planned maintenance activities, an assessment of the overall risk of the activity on plant safety, including benefits to system reliability and performance, is currently performed and documented per AD7.DC6 prior to scheduled work.

Consideration is given to plant and external conditions, the number of activities being performed concurrently, the potential for plant trips, and the availability .of redundant trains.

Risk is evaluated, managed and documented for all activities or conditions based on the current plant state:

  • Before any planned or emergent maintenance is to be performed.
  • As soon as possible when an emergent plant condition is discovered.
  • As soon as possible when an external or internal event or condition is recognized.

Compensatory measures are implemented as necessary and if the risk assessment reveals unacceptable risk, a course of action is determined to restore degraded or failed safety functions and reduce the probabilistic risk.

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Enclosure 1 Description of the Proposed Change 6.0 Regulatory Safety Analysis 6.1 No Significant Hazards Consideration The proposed change will provide a one-time revision to the VEGP Unit 1 Completion Time of TS 3.7.9, Condition B, to allow one inoperable NSCW cooling tower fan for 7 days. The extended Completion Time will permit replacement of the gearbox for Unit 1 Train B NSCW cooling tower fan #3.

1. Does the proposed license amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

The proposed change does not alter any plant equipment or operating practices in such a manner that the probability of an accident is increased.

The proposed changes will not alter assumptions relative to the mitigation of an accident or transient event. Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed license amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve any physical alteration of the plant or a change in the methods governing normal plant operation. 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 proposed amendment involve a significant reduction in a margin of safety?

Based on the operability of the remaining NSCW cooling tower fans, the accident analysis assumptions continue to be met with enactment of the proposed change. The system's design and operation are not affected by the proposed changes. The safety analysis acceptance criteria are not altered by the proposed changes. Finally, the proposed compensatory measures will provide further assurance that no significant reduction in safety margin will occur.

Therefore, the proposed change does not involve a significant reduction in the margin of safety.

Based on the above, SNC concludes that the proposed change presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

6.2 Environmental Assessment This amendment request meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9) as follows:

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Enclosure 1 Description of the Proposed Change (i) The amendment involves no significant hazards consideration.

As described above, the proposed change involves no significant hazards consideration.

(ii) There is no significant change in the types or significant increase in the amounts of any effluents that may be released offsite.

The proposed change does not involve the installation of any new equipment or the modification of any equipment that may affect the types or amounts of effluents that may be released offsite. Therefore, there is no significant change in the types or significant increase in the amounts of any effluents that may be released offsite.

(iii) There is no significant increase in individual or cumulative occupation radiation exposure.

The proposed change does not involve plant physical changes or introduce any new mode of plant operation. Therefore, there is no significant increase in individual or cumulative occupational radiation exposure.

Based on the above, SNC concludes that the proposed change meets the criteria specified in 10 CFR 51.22 for a categorical exclusion from the requirements of 10 CFR 51.22 relative to requiring a specific environmental assessment by the Commission.

7.0 Conclusion The proposed change will provide a one-time revision to the VEGP Unit 1 Completion Time of TS 3.7.9, Condition B to allow an inoperable NSCW cooling tower fan for 7 days. The extended Completion Time will permit replacement of the Unit 1 Train B fan #3 gearbox.

The Plant Review Board reviewed the proposed change to the Technical Specifications and concluded that it does not involve a significant hazard consideration and will not endanger the health and safety of the public.

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Vogtle Electric Generating Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.7.9 Ultimate Heat Sink - Nuclear Service Coolinq Water Tower Fan Enclosure 2 August 3, 2010 Memo re Risk-Based Analysis RBA 10-011-V (without attachments)

DATE: August 3, 2010 FROM: 0. M. Scott TO: MEMORANDUM TO FILE RE: Risk-Based Analysis: RBA 10-011-V A risk-based analysis (RBA) was performed to evaluate the risk impact of taking VEGP Unit 1 Train B NSCW Cooling Tower Fan no.3 (11202W4002F03) out of service (OOS) for 7 days while the unit is at power, Also Train B NSCW Cooling Tower Fan no. 4 (11202W4002F04) will be OOS for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and AFW MDP A will be OOS for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> during the 7 days that fan #3 is OOS.

INTERNAL EVENTS PRA CONTRIBUTION Calculation of Incremental Conditional Core Damage (Large Early Release?

Probability, ICCDP (ICLERP) using Zero Maintenance Model The incremental conditional core damage (large early release) probability, ICCDP (ICLERP) due to the degraded condition lasting for X days is calculated by the equation; Increase in annualized ICCDP(ICLERP) = [CDF(ILERF)Degraded - CDF (LERF)BaseZeroMaint]*[X hours/8760 hours]

where, CDF(LERF)Degraded is the CDF(LERF) assuming the degraded condition lasts for a whole year.

A Zero maintenance model was created from the Rev 4 model by setting all the Maintenance and Test basic events to zero. A Zero maintenance base case CDF(LERF) was calculated.

In this RBA case, the degraded condition is Unit 1 Train B NSCW Cooling Tower Fan #3 OOS for a duration of 7 days. Also Train B NSCW Cooling Tower Fan no.

4 will be OOS during 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of this 7 day period and AFW MDP A will be OOS for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of this 7 day period.

In the Vogtle Rev 4 PRA model, degradation or loss of an NSCW cooling tower or fan is not modeled as a special initiating event. Also for this analysis, there are no common cause failures involved so the CCFs for cooling tower fans are not increased.

The VEGP PRA model of record currently is the VEGPL2UP model. However, VEGP PRA model Revision 4 which has undergone RG 1.200 peer review and is soon to be released, is also available. The Rev 4 model was used for this RBA because it has enhanced NSCW fault tree logic as compared to the VEGPL2UP model.

Rev 4 base case CDF and LERF were quantified. In the Rev 4 model ICCDP and ICLERP were evaluated for three cases.

Case 1 - Train B NSCW Cooling Tower Fan no.3 00S for a whole year Basic event 1 SWFN2-F03---M set to 1.0 (in resulting cutset file 1SWFN2-F03---M was set to TRUE and subsumed)

Case 2 - Train B NSCW Cooling Tower Fan no.3 and Train B NSCW Cooling Tower Fan no. 4 00S for a whole year Basic events 1SWFN2-F03---M and 1SWFN2-F04---M set to 1.0 (in resulting cutset file 1 SWFN2-F03---M and 1SWFN2-F04---M were set to TRUE and subsumed)

Case 3 - Train B NSCW Cooling Tower Fan no.3, Train B NSCW Cooling Tower Fan no. 4, and AFW MDP A OOS for a whole year Basic events 1SWFN2-F03---M, 1SWFN2-F04---M and 1AFPMP4003---M set to 1.0 (in resulting cutset file 1 SWFN2-F03---M, 1SWFN2-F04---M, and 1AFPMP4003---

A and 1AFPMP4003---X were set to TRUE and subsumed). 1E-12/yr and 1E-13/yr were used for truncation limits for CDF and LERF, respectively.

The resulting ICCDP(ICLERP) was compared to the RG 1.177 guidance threshold of less than or equal to 5E-7(5E-8).

Incremental Conditional Case CDFoegraded COFBaseZeroMaint duration(hrs) Core Damage Probability ICCDP 1 1.1438E-05 1.1350E-05 168 hr 1.6877E-09 2 2.7745E-05 1.1350E-05 1 hr 1.8716E-09 3 5.6667E-05 1.1350E-05 1 hr 5.1732E-09 Total 8.7325E-09 Similarly for Large Early Release, Incremental Conditional Case LERIFDegraded LERFBasezeroMaint duration(hrs) Early Release LargeProbability ICLERP 1 3.8268E-08 3.8163E-08 168 hr 2.0137E-12 2 7.4062E-08 3.8163E-08 1 hr 4.0981 E-12 3 3.4607E-06 3.8163E-08 1 hr 3.9070E-10 Total 3.9681E-10 Using the RG 1.177 criteria, the risk increase in terms of ICCDP(ICLERP) calculated for the degraded condition described above, considering internals events only, would be considered small.

EXTERNAL EVENTS RISK CONTRIBUTION The Individual Plant Examination of External Events (IPEEE) was performed as a onetime assessment of the impact of external events and is not periodically updated. SNC is developing a state-of-the-art fire PRA model but it is not yet ready to support detailed risk calculations required for this emergent LAR. Also, a full update of the IPEEE fire PRA model to incorporate changes in methodology and plant modification would be manpower intensive. Therefore, the IPEEE results are used to obtain a bounding estimate of the risk increase due to the unavailability of the NSCW fan.

- Fire Hazard Based on a review of the IPEEE report and its supporting evaluations, the total fire core damage risk was estimated as 1.01 E-5 per year. This represented about 22.7 percent of the core damage risk from the internal events hazards.

Also, based on a review of the results, it was noted that the fire risk contribution from 9 fire zones accounts for more than 60 percent of the total fire risk for Unit 1.

It was also noted that 4 out of the 9 fire zones were train B related fire zones. The unavailability of a NSCW fan #3, which is powered from Train B of the emergency power, has no impact on the fire risk contribution of train B related fire areas because a fire in the B train related zones (e.g., 1-CB-LA-I-88-L-R2) is assessed to result in a loss of either NSCW train B or train B 4kV Switchgear. Finally, it was also noted that the "most significant nonfire failures" in the train A related fire zones, are DG B failures.

Based on the above observations, it is concluded that the fire risk hazard does not have significant impact on the proposed extension to the NSCW tower fan on the following basis:

  • The total fire risk is significantly lower than the internal events risk (about 22.7%) and addition of the fire risk to the internal events risk is not expected to increase the total CDF above 1 E-04/yr. As a result ACDF within Region II and III of Figure 3 of RG 1.174 are considered acceptable. For this particular application the total ACDF estimate is expected to fall within Region III (it is expected to fall within 1 E-06)

" The contribution of unavailability of the fan to the fire risk is insignificant because:

- There is adequate redundancy. The success criteria for NSCW cooling tower fan is one of 4 for non-LOCA events. Most fires events (higher frequency events) do no result in LOCAs. Even in case of lower frequency events such a fire-induced stuck open PORVs, the PRA success criteria of 3 out of 4 fans is met even with fan #3 being OOS.

- The contribution of some of the most risk significant fire scenarios is not affected. As stated about 4 out of the 9 fire risk significant zones are the train B related zone. The unavailability of the fan will not have an impact on the risk contribution from fires in such zones because the a fire in such areas will result in a loss of power to the fan

- The contribution from the remaining fire risk significant zones is not significantly impacted. Again, as stated above, the "most significant nonfire failures" in the train A related fire zones, are DG B failures. Fire-induced non LOCA events are major contributors where random failure of DG B will be risk significant. For such scenarios (non-LOCA loss of offsite power), only 1 of 4 fans is required to keep EDG operable. As a result, unavailability of one fan will have a minimal impact on the failure probability of the DG B.

Therefore, based on the above evaluation and the short duration of the proposed extension in the completion time, it is concluded that the inoperable status of the NSCW fan #3 would not result in any significant change to the base case core damage contribution from fire risk.

- Seismic Hazard Vogtle has been designed to accommodate a safe-shutdown earthquake (SSE) with 0.2g peak ground acceleration (pga). However, due to conservatisms applied to the demand and/or evaluation techniques, most of the Seismic category I structures and equipment were designed and qualified for a 0.3g pga capacity.

The seismic analysis performed in the IPEEE study is intended to act as a performance check on the design, estimating seismic capacity beyond the SSE.

The seismic analysis methodology implemented for Vogtle satisfied the NRC requirements for performing a seismic IPEEE as presented in Generic Letter 88-20, Supplement 4. Seismic events were evaluated using the Seismic Margins Analysis (SMA) method. The SMA methodology uses a deterministic approach to identify the weakest components in terms of High Confidence Low Probability of Failure (HCLPF) during peak ground acceleration. A seismic margin can be expressed in terms of the earthquake motion level that compromises plant safety, the seismic margin assessment determines whether there is high confidence that the plant can survive a given earthquake. No core damage frequency sequences were quantified as part of the IPEEE seismic risk analysis. The seismic margin analysis results showed that the contribution of this hazard to the total risk in insignificant. Additionally, it is judged that the proposed increase in the unavailability of the NSCW fan #3 has an insignificant (well below 1.OE-6 per year) impact on the seismic risk because a seismic event severe enough to result in a failure of a NSCW fan would also result in failure of the redundant fans.

For seismic events of larger magnitudes, equipment on both trains is assumed to fail. In the case of lower level earthquakes an LOSP is assumed to occur. The LOSP IE frequency in the internal events PRA considers LOSP events initiated by seismic events. Therefore the contribution to increase in total CDF (of NSCW of cooling tower fan #3 0OS) due to a seismic event is included in the internal events results and has been shown to be insignificant.

Based on the above evaluation and the short duration of the proposed extension in the completion time, it is concluded that the inoperable status of the NSCW fan #3 would not result in any significant change to the base case core damage contribution from seismic hazard.

- Other External Hazards The Vogtle IPEEE submittal, in addition to the internal fires and seismic events, examined a number of other external hazards:

  • External Flooding
  • Transportation and Nearby Facility Accidents
  • Aircraft Hazard

" Severe Weather & Lightning No risks to the plant occasioned by high winds and tornadoes, external floods, ice, and hazardous chemical, transportation and nearby facility incidents were identified that might lead to significant risk increase during the extended completion time for the NSCW fan #3.

Uncertainty or Sensitivity Issues The PRA analysis of the completion time extension is relatively insensitive to uncertainties. The analysis did not credit equipment repair, so there are no uncertainties to be evaluated for that issue. As compensatory measure, during the repair of the NSCW fan #3, maintenance of important systems to nuclear safety will be restricted. Additionally, it has been confirmed that that common cause is not an issue for the remaining fans. Therefore, issues related to uncertainties should have no effect on the PRA analysis.

ORIGINATOR DATE REVIEWER DATE (oriqinal signed 8/04/2010) (original sigqned 8/04/2010)

Mike Corbett Owen M. Scott Appendix A - Quantification of NSCW Cooling Tower Train Failure Gates ATTACHMENT 1 CAFTA Files The following files were included in a CD ROM VEGPR4.caf: base case VEGP PRA revision 4 CAFTA fault tree model VEGPR4-nofn2.caf: VEGP PRA revision 4 CAFTA fault tree model after setting 1SWFN2-F02---M to TRUE VEGPR4.RR: VEGP PRA revision 4 CAFTA data file VRULER4.caf: VEGP PRA revision 4 Recovery rule CAFTA fault tree VFLAGR4.caf: VEGP PRA revision 4 alignment file CDF-TOTAL.cut: base case CDF cutset file LERF-TOTAL.cut: base case LERF cutset file CDF-TOTAL-nofan2.cut: ICDF cutset file (case with NSCW fan #2 out of service)

LERF-TOTAL-nofan2.cut: ICLERF cutset file (case with NSCW fan #2 out of service)

Vogtle Electric Generating Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.7.9 Ultimate Heat Sink - Nuclear Service Cooling Water Tower Fan Enclosure 3 Marked-up Technical Specifications Page

UHS 3.7.9 3.7 PLANT SYSTEMS 3.7.9 Ultimate Heat Sink (UHS)

LCO 3.7.9 The UHS shall be OPERABLE. With ambient wet-bulb temperature

> 630F, four fans and four spray cells per train shall be OPERABLE. With ambient wet-bulb temperature < 63 0 F, three fans and four spray cells per train shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Nuclear A.1 Restore water 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Service Cooling Water temperature(s) and water (NSCW) basins with level(s) to within limits.

water temperature

  • and/or water level not within limits.

B.1 Restore fan(s) and spray 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B. One NSCW cooling tower with one or more cell(s) to OPERABLE required fans and/or status.

spray cells inoperable.

(continued)

Vogtle Units 1 and 2 3.7.9-35 Amendment No. 5 (Unit 1)

Amendment No. 119 (Unit 2)

Vogtle Electric Generating Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.7.9 Ultimate Heat Sink - Nuclear Service Cooling Water Tower Fan Enclosure 4 Clean Typed Technical Specifications Page

UHS 3.7.9 3.7 PLANT SYSTEMS 3.7.9 Ultimate Heat Sink (UHS)

LCO 3.7.9 The UHS shall be OPERABLE. With ambient wet-bulb temperature

> 63 0 F, four fans and four spray cells per train shall be OPERABLE. With ambient wet-bulb temperature < 63 0 F, three fans and four spray cells per train shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Nuclear A.1 Restore water 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Service Cooling Water temperature(s) and water (NSCW) basins with level(s) to within limits.

water temperature and/or water level not within limits.

B. One NSCW cooling B.1 Restore fan(s) and spray 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s*

tower with one or more cell(s) to OPERABLE required fans and/or status.

spray cells inoperable.

(continued)

Vogtle Units 1 and 2 3.7.9-37 Amendment No. (Unit 1)

Amendment No. 119 (Unit 2)

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