NL-15-0926, Request to Revise Technical Specification LCO 3.5.2 for a One-Time Change to Support a Unit 1 Residual Heat Removal Pump Motor Replacement

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Request to Revise Technical Specification LCO 3.5.2 for a One-Time Change to Support a Unit 1 Residual Heat Removal Pump Motor Replacement
ML15155B593
Person / Time
Site: Vogtle Southern Nuclear icon.png
Issue date: 06/04/2015
From: Pierce C
Southern Co, Southern Nuclear Operating Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-15-0926
Download: ML15155B593 (39)
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Text

Charles R. Pierce Southern Nuclear Regulatory Affairs Director Operating Company, Inc.

40 Inverness Center Parkway Post Office Box 1295 Birmingham, AL 35242 Tel 205.992.7872 Fax 205.992.7601 June 4, 2015 Docket Nos.: 50-424 NL-15-0926 U.S. Nuclear Regulatory Commission ATIN: Document Control Desk Washington, D. C. 20555-0001 Vogtle Electric Generating Plant- Unit 1 Request to Revise Technical Specifications LCO 3.5.2 for a One-Time Change to Support a Unit 1 Residual Heat Removal Pump Motor Replacement Ladies and Gentlemen:

Pursuant to 10 CFR 50.90, Southern Nuclear Operating Company hereby requests an amendment to Vogtle Electric Generating Plant (VEGP) Unit 1 Operating License NPF-68. The proposed change would revise Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.5.2, "ECCS Operating", such that with the '1A' Residual Heat Removal (RHR) pump inoperable for a motor replacement, the Completion Time of Condition 3.5.2.A would be 7 days as opposed to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This TS change would be in effect only for the '1A' RHR pump for the remainder of Cycle 19.

The proposed amendment is needed because the '1 A' RHR pump motor must be replaced and it is preferable to replace the pump motor in Mode 1 as opposed to waiting for the refueling outage. Replacing the pump motor during normal operation will reduce the radiation dose to the workers.

SNC requests approval of the proposed license amendments by August 14, 2015. The proposed change would be effective immediately upon issuance of the amendment. contains a description of the proposed change, the supporting engineering analysis and the no significant hazards determination. Enclosure 2 provides the Reg Guide 1.177, Risk Informed Evaluation. Enclosure 3 contains the marked-up TS page, and Enclosure 4 provides the clean-typed TS page. No changes are proposed to the TS Bases.

This TS revision represents a risk informed licensing change. Accordingly, the proposed change meets the criteria of Regulatory Guide 1.1n, "An Approach for Plant Specific Risk Informed Decision Making: Technical Specifications".

This letter contains no NRC commitments.

U.S Nuclear Regulatory Conunission NL-15-0926 Page 2 If you have any questions, please contact Ken McElroy at (205) 992-7369.

Mr. C.R. Pierce states he is Regulatory Affairs 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.

Rc.~llw::d, C. A. Pierce Regulatory Affairs Director CRP/OCVI Swam to and subscric;, ~:re me this _!j__ day ot_9~~~-----* 2015.

~(4v(JL(~ t

~ Notary Public My commission expires: / D~~ /zor1

Enclosures:

1. Description and Assessment of Proposed Change
2. Risk Informed Evaluation
3. Marked-Up Technical Specifications Page
4. Clean-Typed Technical Specifications Page cc: Southern Nuclear Operating Company Mr. S. E. Kuczynski, Chairman, President & CEO Mr. D. G. Bast, Executive Vice President & Chief Nuclear Officer Mr. D. R. Madison, Vice President- Fleet Operations Mr. M.D. Meier, Vice President- Regulatory Affairs Mr. B. K. Taber, Vice President- Vogtle 1 & 2 Mr. B. J. Adams, Vice President- Engineering Mr. G. W. Gunn, Regulatory Affairs Manager- Vogtle 1 & 2 RType: CVC7000 U.S. Nuclear Regulatory Commission Mr. V. M. McCree, Regional Administrator Mr. R. E. Martin, NRR Senior Project Manager- Vogtle 1 & 2 Mr. L. M. Cain, Senior Resident Inspector- Vogtle 1 & 2 State of Georgia Mr. J. H. Turner, Director- Environmental Protection Division

Vogtle Electric Generating Plant Request to Revise Technical Specifications LCO 3.5.2 for a One-Time Change to Support a Unit 1 Residual Heat Removal Pump Motor Replacement Enclosure 1 Description and Assessment of Proposed Change

Enclosure 1 Description and Assessment of Change 1.0 Description In accordance with 10 CFR 50.90, Southern Nuclear Operating Company requests that Appendix A of Vogtle Electric Generating Plant (VEGP}, Unit 1, Facility Operating License, NPF-68, be amended to provide a one-time change to LCO 3.5.2, "ECCS- Operating". This LCO requires that two Emergency Core Cooling System (ECCS} trains be OPERABLE in Modes 1, 2, or 3. An ECCS train consists of a centrifugal charging system, a Safety Injection (SI} system, and a Residual Heat Removal (RHR} system. Condition 3.5.2.A requires that, if one of the required trains is inoperable, and that 100% of the ECCS flow equivalent to a single OPERABLE ECCS train is available, then the inoperable train must be restored to OPERABLE status in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Otherwise, the reactor must be taken to Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to .Mode 4 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

The proposed amendment revises the Completion Time for Condition 3.5.2.A from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days, but will apply only to the 1A Residual Heat Removal (RHR} pump. Furthermore, this change will only be used one time on VEGP Unit 1 prior to the Cycle 19 shutdown for the purpose of replacing the 1A RHR pump motor.

2.0 Background

2.1 Need for Amendment This work will replace the 1A Residual Heat Removal (RHR} pump motor prior to the VEGP Unit 1 Cycle 19 refueling outage. This will require decoupling the motor, removal of electrical and cooling water connections, removal of physical interferences within the pump room, removal of the motor from the room, installing the new motor in the pump room, mounting the motor to the pump casing, making all the electrical and cooling water connections, running the motor uncoupled, coupling the motor to the pump, alignment, and finally performing a coupled run of the motor and pump.

It is preferable to perform the pump motor replacement prior to the shutdown for the Fall 2015 refueling outage to reduce worker radiation doses. It is estimated that, if the motor replacement is performed during the refueling outage, the total dose to radiation workers would be approximately 2 Rem. The estimate for performing the work with the unit on-line is approximately 1 Rem. Prior to the outage, any water that is within the RHR system will have had almost an entire fuel cycle for the residual radiation to decay thereby reducing the dose rate throughout the pump room. However, if this work is done during the outage, the RHR pump will have been run immediately prior to the motor replacement. This will circulate RCS water throughout the system and will dramatically increase the dose rate within the pump room.

The work is estimated to take longer than the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time of LCO Condition 3.5.2.A. This Technical Specification amendment is being requested as SNC was expecting to have received the Risk Based Completion Time SE by the time this motor would need to be replaced, which could have allowed for entry into a Risk Informed Completion Time (RICT} for LCO 3.5.2.A. ~owever, since the amendment has not been issued, SNC is requesting a one-time TS change to allow a completion time extension of 7 total days. ( Re: Letter to NRC,

Vogtle Electric Generating Plant - Units 1 and 2, License Amendment Request to Revise Technical Specifications to Implement NEI 06-09, Revision 0, "Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS} Guidelines",

September 13, 2012}.

El-l

Enclosure 1 Description and Assessment of Change

2.2 System Description

The Residual Heat Removal (RHR) system at VEGP-1 consists of two pumps, two heat exchangers and the associated piping, valves and instrumentation necessary for operational control. Its functions are as follows:

  • Removes heat energy from the reactor core and the reactor coolant system (RCS) during plant cooldown and refueling operations.
  • Transfers refueling water between the refueling water storage tank and the refueling cavity at the beginning and end of refueling operations.

The ECCS at VEGP consists of three separate systems:

1) Centrifugal charging or high head system
2) Safety injection (SI) or intermediate head system
3) RHR or low head system.

The function of the ECCS is to provide core cooling and negative reactivity to ensure that the reactor core is protected after any of the following accidents:

a. Loss of cooling accident (LOCA), coolant leakage greater than the capability of the normal charging system
b. Rod ejection accident
c. Loss of secondary cooling accident, including uncontrolled steam release or loss of feedwater
d. Steam generator tube ruptu.re (SGTR)

To satisfy LCO 3.5.2, two redundant 100% capacity ECCS trains are required to ensure that sufficient ECCS is available, assuming a single failure affecting either train. One ECCS train consists of a centrifugal charging system, an Sl system, and an RHR system. Furthermore, the ECCS systems at VEGP are interconnected such that the operator is able to use components from opposite trains to achieve the required 100% flow to the core.

El-2 Description and Assessment of Change 3.0 Engineering Analysis 3.1 Defense-in-Depth During the time the 1A RHR pump is out of service, the other RHR system will be Operable.

Additionally, both high head system and both Sl systems will be Operable. Consequently, should an event occur requiring initiation of ECCS, the system will be capable of performing its safety function of providing adequate core cooling and negative reactivity to protect the reactor core, assuming no additional failures. This is inherent in the 3.5.2.A Condition itself, in that a combination of equipment must be maintained Operable such that 100% of the required ECCS flow remains available; if such flow is not available, the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time (CT} cannot be used and the plant must be taken to Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The current 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> CT is based on an NRC reliability study which demonstrated that the impact of having one full ECCS train inoperable is sufficiently small to justify continued operation for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

In this case, the CT would be extended (for the 1A RHR pump only} for a period of up to 7 days.

However, defense-in-depth is maintained as indicated by a risk informed analysis of the specific configuration using Probabilistic Risk Analysis (PRA) tools. This analysis demonstrated that the change is an acceptable impact on plant risk according to Reg Guide 1.177 because incremental conditional core damage probability (ICCDP) is less than 1.0E-5 and incremental conditional large early release probability (ICLERP) is less than 1.0E-6 with effective compensatory measures implemented to reduce the sources of increased risk. The risk informed analysis identified compensatory actions that will be put in place to both decrease the likelihood of failure of a second ECCS system, as well as decreasing the likelihood of an initiating event during the time the 1A RHR pump is out of service. Those actions are described in Enclosure 2.

Defense-in-depth is maintained for the following reasons as well:

  • Prior to removing the RHR pump from service for the purpose of the motor replacement, any assumptions made (e.g., plant equipment configurations} for the risk informed analysis will be verified as necessary to ensure that the conclusions of the risk informed analysis remain valid.
  • Every effort will be made to ensure that the 1A RHR pump is not removed from service for the motor replacement during a period of time of impending inclement weather.
  • Should an event occur with the 1A RHR pump out of service and an accompanying failure of either a centrifugal charging pump or an Sl pump, 100% ECCS flow could still be delivered to the reactor, as a result of the interconnected ECCS systems.

El-3 Description and Assessment of Change 3.2 Safety Margins The proposed TS change is consistent with the principle that sufficient safety margins are maintained based on the following:

Codes and standards (e.g., American Society of Mechanical Engineers (ASME), Institute of Electrical and Electronic Engineers (IEEE) or alternatives approved for use by the NRC) are met. The proposed change is not in conflict with approved codes and standards relevant to the RHR system.

The ECCSs have sufficient capacity to function for the LOCA, Rod Ejection Accident, loss of secondary cooling and the SGTR event. Assuming no additional failures, the FSAR acceptance criteria for these events will be met should such an event occur during the time that the 1A RHR pump is out of service.

3.3 Implementation and Monitoring Program 3.3.1 Three Tiered Implementation Approach The NRC staff has identified a three tiered approach for the evaluation and implementation of risk informed TS changes. Tier 1 addresses PRA assessment capability and insights; Tier 2 the avoidance of risk significant plant configurations, and Tier 3 addresses the management of risk during actual operations.

Below is a brief evaluation of this proposed TS change against the three tiered approach, which is more fully described in Enclosure 2.

The impact of the proposed increased LCO 3.5.2.A CT for the 1A RHR pump has been assessed by risk informed analysis, as documented in Enclosure 2. This is consistent with the Tier 1 guidelines.

In accordance with the Tier 2 guidelines, risk significant combinations of equipment out of service during the time the 1A RHR pump is out of service have been identified, and compensatory actions will be put in place to avoid any high risk equipment out-of-service combinations during that time.

In accordance with the Tier 3 guidelines, the VEGP configuration management tool, (Equipment-Out-of-Service (EOOS)), will effectively monitor the risk of emergent conditions during the period of time that the proposed change is in effect. This will ensure that any additional risk increase due to emergent conditions is appropriately assessed and managed.

El-4 Description and Assessment of Change 3.3.2 Maintenance Rule Control Since this is a one-time change, it is not expected that the additional out-of-service time for the 1A AHA pump will adversely affect the performance of this pump or of the ECCS.

Nevertheless, the AHA pumps are monitored under the VEGP Maintenance Rule Program.

If the pre-established reliability or availability performance criteria for the AHA pumps are exceeded, they are evaluated for the 10 CFR 50.65(a)(1) actions, which requires increased management attention and goal setting in order to restore their performance to an acceptable level.

4.0 Regulatory Analysis 4.1 No Significant Hazards Evaluation This amendment request proposes a one-time change to the Unit 1 Vogtle Electric Generating Plant (VEGP) Technical Specifications Limiting Condition for Operation (LCO) 3.5.2. The one-time change would revise the Completion Time (CT) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days. However, the temporary 7 day CT would only be applicable for a one-time repair of the 1A Residual Heat Removal pump. Furthermore, the revised CT would apply only until the end of the Unit 1 VEGP current operating cycle, cycle 19. At the start of cycle 20, the CT for LCO 3.5.2 would revert to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for all Emergency Core Cooling System pumps.

Southern Nuclear Operating Company (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 Amendmenr, as discussed below:

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

Response: No The emergency core cooling systems (ECCS), including the Residual Heat Removal system, are designed for the mitigation of design basis accidents or transients, such as a Loss of Coolant Accident (LOCA). They are not designed, nor do they serve, for the prevention of those events. Consequently, the proposed amendment does not increase the probability of a previously evaluated accident occurring.

Should an accident occur during the period of time that the RHR pump is out of service, the remaining ECCS components would serve to provide the minimum amount of flow assumed in the accident analysis. Even assuming failure of a charging pump or an Sl system on either of the trains, sufficient ECCS flow would still be provided to the reactor vessel to mitigate the consequences of the event. Furthermore, a risk informed analysis performed in support of this amendment request demonstrates that the consequences of an accident are not significantly increased. As such, the proposed change does not involve a significant increase in the consequences of a previously evaluated accident.

Also, appropriate compensatory measures will be implemented during the time of the extended Completion Time for the RHR pumps. These actions are intended to decrease the chances of an initiating event occurring during the time of the extended CT and also to minimize the chances of losjng any ECCS components.

El-5 Description and Assessment of Change For the above reasons, the proposed changes will not result in a significant increase in the probability or consequences of an accident previously evaluated.

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

Response: No Replacement of the 1A RHR pump motor for the extended Completion Time period does not introduce any new or unanalyzed modes of operation. The replacement of the pump motor does not involve any unanalyzed modifications to the design or operational limits of the RHR system. Therefore, no new failure modes or accident precursors are created due to the motor replacement during the extended Completion Time.

For the reasons noted above, the proposed change will not create the possibility of a new or different accident from any previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

The margin of safety is related to the ability of the fission product barriers to perform their design functions during and following an accident situation. These barriers include the fuel cladding, the reactor coolant system, and the containment. The performance of these fission product barriers will not be significantly affected by the proposed change.

The risk implications of this amendment request were evaluated and found to be acceptable.

During the extended Completion Time for the 1A RHR pump, the ECCS will remain capable of providing adequate flow to the reactor vessel to mitigate the consequences of a design basis event such as LOCA. Also, compensatory actions will be put in place to minimize the probability of an initiating event during the extended CT period as well as to minimize the chances of a loss of one of the remaining ECCSs. A risk informed analysis has also been performed which shows that the incremental plant risk has increased by an acceptable amount.

For the reasons noted above, there is no significant reduction in a margin of safety.

El-6 Description and Assessment of Change 4.2 Applicable Regulatory Requirements The design of the ECCSs satisfies the criteria of 10 CFR 50.36, Technical Specifications",

paragraph (c)(2)(ii), Criterion 3, which states the following:

"(ii) A technical specification limiting condition for operation of a nuclear reactor must be established for each item meeting one or more of the following criteria:

Criterion 3. A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

The ECCSs are described in the VEGP FSAR Section 6.3."

The design of the Residual Heat Removal System and the Emergency Core Cooling Systems satisfies the requirements of 10 CFR 50, Appendix A, General Design Criteria 34 and 35, respectively which state, in part:

Criterion 34- Residual Heat Removal "A system to remove residual heat shall be provided. The system safety function shall be to transfer fission product heat and other residual heat from the reactor core at a rate such that specified acceptable fuel design limits and the design conditions of the reactor coolant pressure boundary are not exceeded".

Criterion 35 - Emergency Core Cooling "A system to provide abundant emergency core cooling shall be provided. The system safety function shall be to transfer heat from the reactor core following any loss of reactor coolant at a rate such that (1) fuel and clad damage that could interfere with continued effective core cooling is prevented and (2) clad metal-water reaction is limited to negligible amounts".

5.0 Environmental Assessment SNC has evaluated the proposed amendment and has determined that 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 off site, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criteria 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 to be prepared in connection with the proposed amendment.

El-7

Vogtle Electric Generating Plant Request to Revise Technical Specifications LCO 3.5.2 for a One-Time Change to Support a Unit 1 Residual Heat Removal Pump Motor Replacement Enclosure 2 Risk Informed Evaluation Risk Informed Analysis

Purpose:

The purpose of this risk-informed evaluation is to document an evaluation of risk impact as directed by Regulatory Guide 1.177 section 2.3, to support a risk-informed Technical Specifications (TS) submittal for a one-time only change to Limiting Condition of Operation (LCO) 3.5.2 condition A completion time (CT). Planned maintenance to replace the Unit 1, Train 'A' Residual Heat Removal (RHR) motor is estimated to take four days, which would exceed the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> completion time allowed by LCO 3.5.2.A. In accordance with RG 1.177, the risk impact of extending this time to 7 days is assessed.

==

Conclusions:==

Implementation of a one-time only TS CT change from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days for LCO 3.5.2 condition A is no more than a small increase in risk to the health and safety of the public, by virtue of the following:

  • The change is an acceptable impact on plant risk because, for internal events, internal floods, internal fires, and seismic events, ICCDP is less than 1.0E-5 and ICLERP is less than 1.0E-6 with effective compensatory measures implemented to reduce the sources of increased risk. (Tier 1)
  • Appropriate restrictions are established for dominant risk-significant configurations associated with the change. (Tier 2)
  • A risk-informed plant configuration control program is implemented, maintained, and controlled by trained personnel in accordance with SNC procedures. The program ensures any potentially risk-significant configurations resulting from maintenance and other operational activities are identified and compensated for. (Tier 3)

Method of Analysis:

Analysis is guided by Regulatory Guide 1.177 Revision 1 section 2.3 (Reference 1). The analysis employs the Vogtle single-top Equipment Out-Of-Service (EOOS) model, revision 4 version 5 (Reference 2) which serves as the Vogtle 1 & 2 Configuration Risk Management Program (CAMP) Model.

E2-1 Risk Informed Analysis Analysis:

Tier 1: Analysis of Risk Impact and Calculated Results According to RG 1.177, Tier 1 is an evaluation of the impact on plant risk of the proposed TS change as expressed by the change in core damage frequency (flCDF), the incremental conditional core damage probability (ICCDP), the change in large early release frequency (flLERF), and the incremental conditional large early release probability (ICLERP). As this license amendment requests a one-time only CT change, the Vogtle 1 & 2 Configuration Risk Management Program (CAMP) model (Reference 2), an at-power, zero-maintenance model, is used for evaluation of ICCDP and ICLERP as allowed by RG 1.177 section 2.4. ICCDP and ICLERP are calculated as follows:

ICCDP =((conditional CDF with the subject equipment out of service and zero equipment unavailabilities) - (baseline CDF with zero equipment unavailabilities)) x (total duration of single CT under consideration)

ICLERP =((conditional LEAF with the subject equipment out of service and zero equipment unavailabilities)- baseline LEAF with zero equipment unavailabilities)) x (total duration of single CT under consideration)

Technical Adequacy of Vogtle 1 & 2 PRA The Vogtle 1 & 2 at-power internal events PRA model (including flooding) and internal fire PRA model conform to the American Society of Mechanical Engineers (ASME) PRA standards at Capability Category (CC) II, which satisfies the guidance of RG 1.200, Revision 2 (Reference 3). Meeting those requirements establishes that the Vogtle 1 & 2 PRA models include the technical attributes expected by Regulatory Guide 1.174 Revision 2 (Reference

4) for use in assessing risk-informed decisions on plant-specific changes to the licensing basis, as in requests for license amendments and technical specification changes. Meeting those requirements also establishes that the Vogtle 1 & 2 PRA models include the technical attributes expected by Regulatory Guide 1.177 (Reference 1) for use in assessing safety implications of the TS change being requested.

The Vogtle 1 & 2 internal events (including internal flooding) model has been subjected to several peer reviews and self-assessments including the most recent peer review performed in accordance with the 2007 version of the ASME PRA standard (Reference 6). All open peer review findings have been resolved.

The VEGP fire PRA was peer reviewed in 2012 by the PWROG against the Combined ASMEIANS Standards, RG 1.200, Revision 2 and Topical Report NEI 07-12. A self-assessment of the fire PRA against the ASMEIANS RA-SA-2009 (Reference 5) was performed by SNC staff prior to the PWROG peer review. Open findings were reviewed and none impact the use of the model for evaluations related to RHR.

Capability of Vogtle 1 & 2 PRA The RHR system is included in the Vogtle 1 & 2 PRA models for accomplishing the following functions:

E2-2 Risk Informed Analysis

  • High pressure recirculation following LOCA
  • Low pressure injection following LOCA
  • Low pressure recirculation following LOCA
  • Long-term cooling following small LOCA
  • Long-term feed and bleed For each of these functions, success is achieved by operation of 1 of 2 RHR trains. The RHR trains are modeled at the component level and include operator actions and common cause failures.

The Vogtle 1 & 2 CAMP model (Reference 2) combines the baseline internal events (including internal flooding) PRA model and the baseline internal fire PRA model into a single top model. The CAMP model can be configured to apply seismic core damage frequency (CDF) and large early release frequency (LEAF) factors based on bounding analysis of seismic risk. The Vogtle 1 & 2 CAMP model is an at-power, zero-maintenance model (i.e. it directly addresses plant configurations during plant modes 1 and 2 of reactor operation and maintenance/test event probabilities are set to zero). The process of creating the CAMP model from the baseline PRA models ensures:

  • preservation of the CDF and LEAF quantitative results,
  • conservation of the quality of the peer-reviewed PRA models, and
  • accommodation of changes in risk due to time-of-year, time-of-cycle and configuration-specific considerations.

The failure rates for the RHR pump fails to start and fails to run events used in the Vogtle 1

& 2 CAMP model were validated by review of recent Vogtle 1 & 2 operating history.

The Vogtle 1 & 2 CAMP model is suitable for use in supporting the license amendment request for a one-time only completion time change to LCO 3.5.2.A. The model adequately assesses risk increases due to internal events, internal floods, internal fires, and seismic events. Analyses of other external hazards are performed by qualitative methods. No changes are necessary to the Vogtle 1 & 2 PRA models for use in this TS change evaluation. Because the change is for a one-time planned event, the specific configuration can be closely controlled and a no-maintenance model is more appropriate than using an average maintenance model.

Quantitative Analyses of Internal Events. Internal Floods, Internal Fires, and Seismic Events Quantitative analyses of internal events, internal floods, internal fires, and seismic events employ the use of the Vogtle 1 & 2 CAMP model (Reference 2). All calculations are performed at a truncation limit of 1E-11. The adequacy of this truncation was verified by comparison to calculation results at a truncation limit of 1E-12.

Since the amendment request is for a one-time only CT change, the overall change in average CDF and LEAF is not analyzed as allowed by RG 1.177 section 2.4.

To determine ICCDP and ICLERP, CDF and LEAF are calculated for a baseline, zero-maintenance case and for a preventive maintenance (PM) case. The baseline values are E2-3 Risk Informed Analysis calculated based on typical train 'B' system alignments, which reflects the system alignments expected during use of the one-time extended RHR train 'A' outage.

For the PM case, the Vogtle 1 & 2 CRMP model is further configured as follows:

  • Unit 1 RHR train 'A' pump (11205P6001) failure to start and failure to run events are changed from their nominal values to failed (1.0),
  • seismic risk factors are enabled, and
  • RHR common cause factors are set to zero per RG 1.177 Appendix A because the TS CT is for planned maintenance and the common cause group is only two components.

As configured, the Vogtle 1 & 2 CRMP model fully quantifies CDF and LERF model logic for internal events, internal floods, and internal fires. Seismic risk increases are accounted for by application of bounding flCDFsErsMrc and flLERFsErsMrc values of 2E-05 per reactor year and 2E-7 per reactor year, respectively to each evaluated configuration. The seismic risk factors are developed by bounding analysis documented in Attachment 1.

Table 1 reports the calculated CDF and LERF for the baseline case and the preventive maintenance (PM) case, and reports the resultant increase in CDF and LERF. Each calculation is performed at a truncation limit of 1E-11.

Table 1 CDF and LERF for Baseline and PM Case Risk Measure Baseline PM Case Increase CDF 6.15E-05 4.51 E-04 3.89E-04 LERF 1.92E-06 1.15E-05 9.61E-06 All of the calculations assume zero maintenance on other structures, systems, and components (SSG). The calculated ICCDP and ICLERP reflect the entire 7 day completion time for the 'A' train RHR pump outage and do not credit implementation of risk management actions.

ICCDP = (PM Case- Baseline) * (7/365) = 7.47E-06 ICLERP =(PM Case- Baseline)* (7/365) = 1.84E-07 To verify underestimation has not taken place due to truncation limits, results are compared to calculation results using a decade lower truncation limit. Calculation results reported in Table 1 are performed at a truncation limit of 1E-11. At a truncation limit of 1E-12, the deltas between the PM cases and the baseline cases are equal to the increases reported in Table 1; therefore, a truncation limit of 1E-11 is appropriate.

Attachment 2-A lists the top 10 CDF cutsets for the baseline, zero-maintenance case.

Attachment 2-B lists the top 10 CDF cutsets for the preventive maintenance case. All of the top 10 cutsets are from fire initiating events; therefore, Attachment 2-C lists the top 10 CDF internal events cutsets for the preventive maintenance case.

E2-4 Risk Informed Analysis Attachment 2-D lists the top 10 LEAF cutsets for the baseline, zero-maintenance case.

Attachment 2-E lists the top 10 LEAF cutsets for the preventive maintenance case.

Qualitative Analyses of Other External Hazards The Individual Plant Examination of External Events (IPEEE) for Vogtle Units 1 and 2 (Reference 7) and its subsequent update (Reference 8) provide assessment of the vulnerability of the site to other external hazards. The application of preliminary screening criteria resulted in the need to further analyze seven external hazards by bounding analyses. Hazards not screened that were evaluated by bounding analyses were aircraft impact, extreme winds and tornadoes, external flooding including intense local precipitation, industrial and military facility accidents, pipelines accidents, and turbine-generated missiles.

The bounding analyses demonstrate that these external hazards do not pose a credible threat to Vogtle 1 & 2. The assessment complies with the high-level and supporting requirements of the ASMEIANS PRA standard (Reference 5).

Sensitivity and Uncertainty Analyses The CT change subjects the plant to a variation in exposure to the same risks (no new initiating events or failure modes are introduced), thus the PRA models are able to accurately predict the change in CDF and LEAF for the variation in exposure.

Tier 2: Restrictions are established for Dominant Risk-Significant Configurations According to RG 1.177, Tier 2 is an identification of potentially high-risk configurations that could exist if equipment, in addition to that associated with the change, were to be taken out of service simultaneously or other risk-significant operational factors, such as concurrent system or equipment testing, were also involved. The objective of this part of the evaluation is to ensure that appropriate restrictions on dominant risk-significant configurations associated with the change are in place.

Risk Management Actions Based on configuration-specific insights provided by the Vogtle 1 & 2 CAMP softw~re tool, restrictions are established for entry into the one-time 1A RHR 7 day completion time. The following Unit 1 SSCs must be functional:

  • Auxiliary Component Cooling Water (ACCW) System
  • Train 'B' Nuclear Service Cooling Water (NSCW) System
  • Train '8' Safety Injection System
  • Train 'A', '8', and 'C' Auxiliary Feedwater (AFW) Systems Based on configuration-specific insights provided by the Vogtle 1 & 2 CAMP software tool, SNC will implement risk management actions during use of the one-time 1A RHR 7 day completion time.

E2-5

Enclosure 2 Risk Informed Analysis

  • The following SSCs will be protected in accordance with the SNC equipment protection program:

o SSCs listed above that must be operable/functional prior to entry into the one-time CT o 4160VAC Electrical Bus 1BA03 o 480VAC Switchgear 1BB06 & 1BB 16 o 480VAC Motor Control Centers 1BBB & 1BBD o 125VDC Bus 1BD1 o 125VDC Panel 1BY2B o AC Inverter 1BD1112 o Fire pumps

  • For the fire zones in Table 2, maintenance activities involving unavailability of fire protection equipment (detection, suppression or fire barriers), hot work, or introduction of transient combustible materials will be restricted.

Table2 Risk-Significant Fire Zones I Fire Zone I Description 11062 jUNIT 1 CONTROL BUILDING LEVEL B TRAIN B PENETRATION ROOM B065

~~NIT 1 CONTROL BUILDING LEVEL B TRAIN B I CHANNEL 2 EQUIPMENT 11079A ROOM B047

~~NIT 1 CONTAINMENT BUILDING LEVELS C, B, A, 3 ROOMS C10, B01, B07, 11140B B08,B10,B16,A01,A06, 109,111

~~NIT 1 CONTROL BUILDING LEVEL A TRAIN B SHUTDOWN PANEL ROOM 11098 A043 11152 !UNIT 1 CONTROL BUILDING LEVEL B TRAIN B ELECTRICAL CHASE B046

!.UNIT 1 CONTAINMENT BUILDING LEVELS B, A, 1 ROOMS B002, B011, A002, 11140C A005, 102-105

~~NIT 1 CONTROL BUILDING LEVEL A TRAIN B MCC ROOM A077[Area 1158-11158 JB]

~ ~NIT 1 CONTROL BUILDING LEVEL B TRAIN D I CHANNEL 4 EQUIPMENT 11056A ROOM B048

.~UNIT 1 AUXILIARY BUILDING LEVEL 2 AB ELEVATOR #3 VESTIBULE 201, 11055 TRAIN B COMPONENT COOLING WATER HEAT 11158-JB !UNIT 1 CONTROL BUILDING LEVEL A TRAIN B MCC ROOM A077

!*UNIT 1 AUXILIARY BUILDING LEVEL 2 AB ELEVATOR #3 VESTIBULE 201, 11055-DT TRAIN B COMPONENT COOLING WATER HEAT 1UNIT 1 AUXILIARY BUILDING LEVEL 2 TRAIN A COMPONENT COOLING

,1054-DV WATER HEAT EXCHANGER ROOM 203 1

~~NIT 1 CONTROL BUILDING LEVEL B TRAIN C I CHANNEL 3 EQUIPMENT 11077A ROOM B055 E2-6 Risk Informed Analysis Note that none of the risk management actions are credited quantitatively. The benefits of these actions are generally not quantifiable. The risk management actions described above provide more rigorous control of the plant configuration during the 1A AHA 7 day CT.

E2-7 Risk Informed Analysis Tier 3: Configuration Risk Management According to RG 1.177, Tier 3 is the establishment of an overall configuration risk management program (CAMP) to ensure that other potentially lower probability, but nonetheless risk-significant, configurations resulting from maintenance and other operational activities are identified and compensated for.

Configuration Risk Management Program Southern Nuclear has an established configuration risk management program that implements 10CFR50.65(a)(4) requirements. The Vogtle 1 & 2 CAMP software tool is used to perform real time calculations of CDF and LEAF impacts to internal event (including flooding) and internal fire hazards. Trained SNC staff use procedures and the Vogtle 1 & 2 CAMP software tool to assess and manage the following:

  • risk increases associated with planned maintenance activities prior to performance of the activities, and
  • risk increases associated with unplanned operational events.

The process focuses on avoidance of risk-significant configurations and actions to reduce the risk associated with risk-significant configurations. The CAMP software tool provides key risk insights that enable development of effective, configuration-specific, risk management actions as required by CAMP procedures. The CAMP software tool assists in development of risk management actions by providing the following configuration-specific information:

  • important mitigating components to maintain functional,
  • important fire zones containing important mitigating components, and
  • important fire zones in which fire can generate a risk significant initiating event.

SNC procedures and sub-tier instructions and guidelines provide guidance and requirements for creating and maintaining the SNC PRA models, the CAMP model, and the CAMP software tool for implementation of 10CFR50.65(a)(4). The Vogtle CAMP process applies a graded approach to risk management depending on the integrated risk expected for the duration of any specific configuration.

The SNC internal (including flooding), fire and CAMP models are maintained using a continuous configuration control process. Changes to the plant and modeling errors or improvements are tracked and evaluated as they are identified to ensure that the model reflects the as-built, as-operated plant. Periodic updates are issued as needed as shown in the documents listed in Reference 2.

E2-8 Risk Informed Analysis Analysis Inputs/

References:

1. Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications," Revision 1, May 2011
2. The following document the Vogtle single-top EOOS Model Revision 4 Version 5:
a. PRA-BC-V-10-002, "Vogtle Units 1 and 2 Revision 4 EOOS Model"
b. PRA-CN-V-11-001, Vogtle Units 1 and 2 EOOS Model Update to R4V1"
c. PRA-CN-V-11-003, Vogtle Units 1 and 2 EOOS Model Update to R4V2"
d. PRA-CN-V-13-003, Vogtle Units 1 and 2 EOOS Model Update to R4V3, Including Fire for Use in Maintenance Rule 10CFR50.65(a)(4) Assessments of Maintenance Activities"
e. PRA-CN-V-14-001, Vogtle Units 1 and 2 EOOS Model Update to R4V4"
f. PRA-CN-V-14-002, "Vogtle Units 1 and 2 EOOS Model Update to R4V5"
3. RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2, March 2009
4. Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 2, May 2011
5. ASME/ANS RA-Sa-2009, "Standard for Levei1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," Addendum A to RAS-2008, ASME, February 2009
6. ASME RA-Sc-2007, "ASME RA-S-2002 Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications," Addenda to ASME RA-S-2002, August 31, 2007
7. Vogtle Electric Generating Plant, Units 1 and 2, Individual Plant Examination of External Events," November 1, 1995 8 "Vogtle Electric Generating Plant Units 1 and 2, Evaluation of Other External Hazards,"

Calculation No. PRA-BC-V-11-008, Revision 0, October 18, 2011 Attachments:

1) Seismic Bounding Analysis 2-A) Top 10 CDF Cutsets, Baseline Case 2-B) Top 10 CDF Cutsets, PM Case 2-C) Top 10 CDF Internal Events Cutsets, PM Case 2-D) Top 10 LEAF Cutsets, Baseline Case 2-E) Top 10 LEAF Cutsets, PM Case E2-9

Enclosure 2 Risk Informed Analysis - Seismic Bounding Analysis The purpose of this attachment is to present the analysis to bound the potential seismic impact and include it in the decision-making process. The process employs the following three steps.

1. Estimate Bounding CDF
2. Evaluate Potential Risk Increases Due to Out of Service Equipment
3. Qualitatively Evaluate Bounding LEAF Contribution Estimate Bounding Seismic CDF The NRC recently published information on the estimates of the seismic risk levels for all plants in the Central and Eastern United States (CEUS) as part of Generic Issue 199 (Reference 1-1).

Seismic hazards are a subject of considerable uncertainty. In order to address the changing state of knowledge on seismic hazards, the NRC Staff developed a technical analysis (Reference 1-2) that computed conservative estimates of seismic risk for all plants in the Central and Eastern United States (CEUS) using estimates of the seismic risk levels developed as part of Generic Issue 199 (Reference A.1-1 ). The NRC Staff analysis used a variety of calculation approaches to compute a conservative estimate of the SCDF using three different seismic hazard sources. The results of these analyses for the VEGP site are presented in Table 1-1.

Table 1-1 Estimates of Total Seismic Core Damage Frequency from Appendix D of Ref. 1-2 Calculation Approach Hazard Source Maximum Simple IPEEE Weakest Highest Spectral Average Weighted Link Estimate Result Average Model 1989 EPRI 2.2E-06 2.0E-06 1.9E-06 2.6E-06 2.6E-06 (Reference 1-3) 1994 LLNL 2.0E-05 1.5E-05 1.4E-05 2.0E-05 2.0E-05 (Reference 1-4) 2008 USGS 6.6E-06 5.0E-06 4.8E-06 7.1E-06 7.1 E-06 (Reference 1-5)

These estimates span a fairly wide range, with the maximum value generated using the 1994 Lawrence Livermore National Lab (LLNL) hazard curve along with conservative estimates of the seismic fragility. Using these conservative analyses, the maximum total SCDF is computed to be 2E-5/yr. This represents the convolution of the VEGP seismic hazard curve with an assumed limiting plant fragility based on the high confidence of low probability of failure (HCLPF) of 0.3g, as reported in the VEGP IPEEE (Reference 1-6). Such methods have been shown to provide a conservative estimate of SCDF. By adopting the *maximum estimate generated by various methods, this provides a bounding estimate of the SCDF.

E2-10

Enclosure 2 Risk Informed Analysis Attachment 1 - Seismic Bounding Analysis Evaluate Potential Risk Increases Due to Out of Service Equipment The approach taken to the computation of SCDF in Reference 1-2, assumes that the SCDF can be based on the likelihood that a single seismic-induced failure leads to core damage. This approach is bounding and implicitly relies on the assumption that seismic-induced failures of equipment show a high degree of correlation (i.e., if one SSC fails, all similar SSCs will also fail). This assumption is conservative, but direct use of this assumption in evaluating the risk increase from out of service equipment could lead to an underestimation of the change in risk.

However, if one were to assume no correlation at all in the seismic failures, then the seismic risk would be lower than the risk predicted by a fully correlated model, but the change in risk using the un-correlated model with a redundant piece of important equipment out of service would be back up to the level predicted by the correlated model.

If the industry accepted approach (Reference 1-2) of correlation is assumed, the conditional core damage frequency given a seismic event will remain unaltered whether equipment is out of service or not. Thus, the risk increase due to out of service equipment cannot be greater than the total SCDF estimated by the bounding method used in Reference 1-2. That is, for the VEGP site, the delta SCDF from equipment out of service cannot be greater than 2E-5/yr. This conservative bounding value is used in the risk calculations to evaluate the impact of maintenance on the seismic initiator.

Evaluate Bounding Seismic LERF Contribution The current VEGP internal events PRA (Reference 1-7) includes a comprehensive treatment of LERF due to internally initiated events. Table 1-2 provides a summary of the results of the internal events analysis. These results show that the VEGP containment is robust with respect to LERF contributors, except with the scenario initiated by a bypass event (i.e., SGTR or ISLOCA). All other scenarios, including Station Blackout (SBO) show a conditional probability of LERF of less than 0.01.

Seismic events would not be expected to induce containment bypass scenarios. Therefore, a bounding conditional large early release probability for seismic events (CLERPselsmic) is assumed to be 0.01. The incremental bounding large early release frequency from seismic events (ILERFselsmic) is then computed as:

ILERFseismic =ICDFseismlc

  • 0.01 =2E-07 E2-11 Risk Informed Analysis - Seismic Bounding Analysis Table 1-2 Conditional Large Early Release Probability from Internal Event PRA Initiating LERF Description CDF (/yr) CLERP Event (lyr)

%1SLOCA INTERFACING SYSTEMS LOCA IDENTIFIER 1.03E-09 1.03E-09 100.0%

%SGTR SGTR IE IDENTIFIER 1.12E-07 3.94E-08 35.2%

SECONDARY SIDE BREAK UPSTREAM OF MSIVs INITIATING EVENT

%SSBI 2.15E-07 1.43E-09 0.7%

IDENTIFIER

%L0120VAB LOSS OF 120VAC PANELS A AND B SPECIAL IE IDENTIFIER 5.81 E-09 1.53E-11 0.3%

%MLOCA MEDIUM LOCA IE IDENTIFIER 1.48E-06 3.60E-09 0.2%

%LODCB LOSS OF DC BUS 1B SPECIAL INITIATOR IDENTIFIER 2.44E-07 4.64E-10 0.2%

SECONDARY SIDE BREAK DOWNSTREAM OF MSIVs INTIATING EVENT

%SSBO 1.67E-07 3.04E-10 0.2%

IDENTIFIER

%LODCA LOSS OF DC BUS 1A SPECIAL INTIATOR IDENTIFIER 2.13E-07 3.15E-10 0.1%

%LLOCA LARGE LOCA IE IDENTIFIER 1.13E-08 1.63E-11 0.1%

%SBO Station Blackout IE IDENTIFIER 6.27E-06 8.75E-09 0.1%

%LONSCW LOSS OF NSCW IDENTIFIER 2.24E-06 3.09E-09 0.1%

%AVA REACTOR VESSEL RUPTURE IE IDENTIFIER 9.10E-08 1.25E-10 0.1%

%1SINJ INADVERTENT Sl INJECTION IE IDENTIFIER 2.52E-06 3.46E-09 0.1%

%L04160VA LOSS OF 4.16KV BUS A SPECIAL IE IDENTIFIER 1.14E-06 1.56E-09 0.1%

%L04160VB LOSS OF 4.16KV BUS B SPECIAL IE IDENTIFIER 5.19E-07 7.00E-10 0.1%

%LOSP LOSS OF OFFSITE POWER IE IDENTIFIER 4.72E-06 6.18E-09 0.1%

%0TRAN OTHER TRANSIENTS IE IDENTIFIER 7.00E-07 9.13E-10 0.1%

%SLOCA SMALL LOCA IE IDENTIFIER 3.10E-07 3.98E-10 0.1%

%TTRIP TURBINE TRIP IE IDENTIFIER 4.79E-07 6.14E-10 0.1%

%RTRIP REACTOR TRIP IE IDENTIFIER 4.25E-07 5.43E-10 0.1%

%LOC LOSS OF CONDENSER IE IDENTIFIER 2.68E-07 3.22E-10 0.1%

%ATWT ATWT IDENTIFIER 1.87E-07 2.24E-10 0.1%

%LOFW LOSS OF FEED WATER IE IDENTIFIER 1.71 E-07 1.98E-10 0.1%

%LOSINJ LOSS OF SEAL INECTION IDENTIFIER 3.61E-08 3.70E-11 0.1%

E2-12 Risk Informed Analysis - Seismic Bounding Analysis Table 1-2 Conditional Large Early Release Probability from Internal Event PRA Initiating LEAF Description CDF (/yr) CLERP Event (/yr)

%LOlA LOSS OF INSTRUMENT AIR SPECIAL INTIATOR IDENTIFIER 8.53E-09 3.79E-12 0.0%

Total Total CDFILERF 2.25E-05 7.37E-08 0.3%

E2-13 Risk Informed Analysis - Seismic Bounding Analysis Conclusion The analysis provides the technical basis for addressing the seismic-induced core damage risk for Vogtle 1 & 2 by adding delta CDF and delta LEAF factors to account for a bounding estimate of the configuration risks due to seismic events.

Calculations performed by the Vogtle 1 & 2 CAMP model can add an incremental 2E-05/year and 2E-07/year seismic contribution to the configuration-specific delta CDF/delta LEAF attributed to contributions from internal events, floods, and internal fire events.

References 1-1. Staff Report, "Implications of Updated Probabilistic Seismic Hazard Estimates In Central And Eastern United States On Existing Plants, Safety/Risk Assessmenf', ML100270639, August 2010.

1-2. Generic Issue 199, "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants", IN2010-18, September 2, 2010.

1-3. EPRI NP-6395-D, 1989, "Probabilistic Seismic Hazard Evaluation at Nuclear Plant Sites in the Central and Eastern United States: Resolution of the Charleston Issue," Electric Power Research Institute, Palo Alto, CA.

1-4. NUREG-1488, 1994, "Revised Livermore Seismic Hazard Estimates for Sixty-Nine Nuclear Power Plant Sites East of the Rocky Mountains", U.S. Nuclear Regulatory Commission, Washington, D.C.

1-5. Petersen, M.D, and 14 others, 2008, "Documentation for the 2008 Update of the United States National Seismic Hazard Maps by the National Seismic Hazard Mapping Project,"

United States Geological Survey Open-file Report 2008-1128.

1-6. Georgia Power Company, Vogtle Electric Generating Plant, Units 1 and 2, Individual Plant Examination of External Events," November 1, 1995.

1-7. Southern Nuclear Co., VEGP Level 1 and 2 PRA Model Revision 4- at power, internal events", Calculation No. PRA-BC-V-07-003, Rev. 0, December 15, 2010.

E2-14 Risk Informed Analysis -A- Top 10 CDF Cutsets, Baseline Case

  1. Cutset Event Inputs Description Pro b. Pro b.

1 1.77E-06 3.26E-02 %LOSP LOSS OF OFFSITE POWER IE IDENTIFIER 4.96E-02 1DGDGG4001---X DG1A FAILS TO RUN BY RANDOM CAUSE (24 HR MISSION TIME) 4.96E-02 1DGDGG4002---X DG1B FAILS TO RUN BY RANDOM CAUSE (24 HR MISSION TIME) 7.90E-01 RCPSL-21GPM RCP SEAL LEAK 21 GPM/PUMP AFTER 13 MIN. TOTAL LOSS OF SEAL COOLING 3.10E-01 WILSON-SWYD-LOSP PLANT WILSON SWYD FAILS GIVEN VEGP LOSP (GRID, SEV OR EXT. WEATHER) 9.00E-02 NACR-G OFFSITE POWER RECOVERY FAILURE (general)- 1DG initially running 2 l.GOE-06 3.26E-02 %LOSP LOSS OF OFFSITE POWER IE IDENTIFIER 2.48E-04 1SWMV1668A69ADCC NSCW CT SPRAY VALVES HV1668A & 69A FAILS TO OPEN DUE TO CCF 1.98E-01 RCPSL-182GPM RCP SEAL LEAK 182 GPM /PUMP 13 MIN AFTER SBO 3 1.44E-06 1.00E+OO %LONSCW LOSS OF NSCW IDENTIFIER 3.43E-04 1SWPM1234---&XCC NSCW PUMPS 1, 2, 3, & 4S PUMPS FAIL TO RUN (1 YEAR)- CCF 2.00E-02 OA-OSW-------H NSCW PUMP 1,2,3,4,5, OR 6 INITIATOR AND OPERATOR FAILS TO ESTABLISH 1 NSCW PUMP 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

4 1.12E-06 4.86E-04 %MLOCA MEDIUM LOCA IE IDENTIFIER 2.30E-03 OAR_HPML-----H OPERATOR FAILS TO ESTABLISH HIGH PRESSURE RECIRC- MLO 5 1.03E-06 5.06E-02 %1SINJ INADVERTENT SIINJECTION IE IDENTIFIER 9.65E-05 1SWFN40RMORE- 4 OR MORE NSCW FANS FAIL TO START DUE TO COMMON CAUSE FAILURE ACC 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

E2-15 Risk Informed Analysis -A- Top 10 CDF Cutsets, Baseline Case

  1. Cutset Event Inputs Description Pro b. Pro b.

6 l.OlE-06 l.OOE+OO %LONSCW LOSS OF NSCW IDENTIFIER 4.80E-06 1SWPMALL----&XCC CCF AFFECTING ALL NSCWPS REGARDLESS OF DIFFERENT OP. HISTORIES (1YR) 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

7 9.26E-07 4.41E-06 %FIRE_A105-JY_P2 MCB Panel QMCB Al Fire - NSCW - Initiator 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

8 9.06E-07 S.OGE-02 %1SINJ INADVERTENT SIINJECTION IE IDENTIFIER 8.52E-05 1ACSDU301302-FCC COMMON CAUSE FAILURE OF LOAD SEQUENCER 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

9 6.54E-07 3.26E-02 %LOSP LOSS OF OFFSITE POWER IE IDENTIFIER 1.84E-02 1AC-BRUN-LS-FCC COMMON CAUSE FAILURE OF LS RELAYS ON HEAVILY LOADED TRAIN 4.96E-02 1DGDGG4001---X DG1A FAILS TO RUN BY RANDOM CAUSE {24 HR MISSION TIME) 7.90E-01 RCPSL-21GPM RCP SEAL LEAK 21 GPM/PUMP AFTER 13 MIN. TOTAL LOSS OF SEAL COOLING 3.10E-01 WILSON-SWYD-LOSP PLANT WILSON SWYD FAILS GIVEN VEGP LOSP (GRID, SEV OR EXT. WEATHER) 9.00E-02 NACR-G OFFSITE POWER RECOVERY FAILURE (general)- 1DG initially running 10 6.31E-07 3.26E-02 %LOSP LOSS OF OFFSITE POWER IE IDENTIFIER 8.78E-04 1DGDGU1SU2---XCC DG1A, DG1B, AND A UNIT 2 DG FAIL TO RUN DUE TO CCF (24 HR MISSION TIME) 7.90E-01 RCPSL-21GPM RCP SEAL LEAK 21 GPM/PUMP AFTER 13 MIN. TOTAL LOSS OF SEAL COOLING 3.10E-01 WILSON-SWYD-LOSP PLANT WILSON SWYD FAILS GIVEN VEGP LOSP (GRID, SEV OR EXT. WEATHER) 9.00E-02 NACR-G OFFSITE POWER RECOVERY FAILURE (general)- lOG initially running E2-16 Risk Informed Analysis -B -Top 10 CDF Cutsets, PM Case

  1. Cutset Event Inputs Description Pro b. Pro b.

1 1.58E-04 2.39E-04 %FIRE_1098-JD_B1 Train B Shutdown Panei1-1605-P5-SDB Fire- No Spr -Initiator 1.00E+00 1LPPMRHRA--A RHR PUMP A FAILS TO START 6.60E-01 1RCPORV0456A- PRESSURIZER PORV PV-0456A SPURIOUSLY OPENS DUE TO FIRE u 0.66 2 2.37E-05 3.58E-05 %FIRE_1079A-19_B1 125 VDC Swgr 1BD1 Fire - Initiator 1.00E+OO lLPPMRHRA----A RHR PUMP A FAILS TO START 6.60E-01 1RCPORV0456A- PRESSURIZER PORV PV-0456A SPURIOUSLY OPENS DUE TO FIRE u 0.66 3 1.81E-05 8.61E-05 %FIRE_1140B-S1_E Elevation 185 - North - Initiator l.OOE+OO lLPPMRHRA----A RHR PUMP A FAILS TO START 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

4 1.13E-05 1.71E-05 %FIRE_1079A-19_ C1 Battery Charger 1BD1CA Fire- Initiator 1.00E+00 lLPPMRHRA----A RHR PUMP A FAILS TO START 6.60E-01 1RCPORV0456A- PRESSURIZER PORV PV-0456A SPURIOUSLY OPENS DUE TO FIRE u 0.66 5 1.13E-05 1.71E-05 %FIRE_1079A-19_D1 Battery Charger 1BD1CB Fire - Initiator 1.00E+OO lLPPM RHRA----A RHR PUMP A FAILS TO START 6.60E-01 1RCPORV0456A- PRESSURIZER PORV PV-0456A SPURIOUSLY OPENS DUE TO FIRE u 0.66 6 9.96E-06 9.96E-06 %FIRE_A105-JY_AT3 MCR PanellBCQSPB Fire- Section 01- Initiator l.OOE+OO lLPPMRHRA----A RHR PUMP A FAILS TO START E2-17 Risk Informed Analysis -B -Top 10 CDF Cutsets, PM Case

  1. Cutset Event Inputs Description Pro b. Pro b.

7 8.36E-06 3.98E-05 %FIRE_A105-JY_J MCR Panel QPP2 Fire- Initiator 1.00E+OO lLPPMRHRA----A RHR PUMP A FAllS TO START 2.10E-01 RCPSl-GT21GPM RCP SEAl lEAK GREATER THAN 21 GPM/RCP AFTER TOTAl lOSS OF SEAl ClG.

8 8.36E-06 3.98E-05 %FIRE_A105-JY_l MCR Panel QPCP Fire - Initiator 1.00E+OO 1lPPMRHRA----A RHR PUMP A FAllS TO START 2.10E-01 RCPSl-GT21GPM RCP SEAl lEAK GREATER THAN 21 GPM/RCP AFTER TOTAl lOSS OF SEAl ClG.

9 3.98E-06 3.98E-06 %FIRE_1120-KH_B U1 CSR B Term Cabinet 1NCPT02 Fire - Initiator 1.00E+00 lLPPMRHRA---A RHR PUMP A FAllS TO START 10 3.98E-06 3.98E-06 %FIRE_1120-KH_C U1 CSR B Term Cabinet 1BCPT04 Fire- Initiator 1.00E+OO 1lPPMRHRA----A RHR PUMP A FAllS TO START E2-18 Risk Informed Analysis -C- Top 10 CDF Internal Events Cutsets, PM Case

  1. Cutset Event Inputs Description Prob. Prob.

1 1.77E-06 3.26E-02 %LOSP LOSS OF OFFSITE POWER IE IDENTIFIER 4.96E-02 1DGDGG4001---X DG1A FAILS TO RUN BY RANDOM CAUSE (24 HR MISSION TIME) 4.96E-02 1DGDGG4002---X DG1B FAILS TO RUN BY RANDOM CAUSE (24 HR MISSION TIME) 7.90E-01 RCPSL-21GPM RCP SEAL LEAK 21 GPM/PUMP AFTER 13 MIN. TOTAL LOSS OF SEAL COOLING 3.10E-01 WILSON-SWYD-LOSP PLANT WILSON SWYD FAILS GIVEN VEGP LOSP (GRID, SEV OR EXT. WEATHER) 9.00E-02 NACR-G OFFSITE POWER RECOVERY FAILURE (general)- 1DG initially ruuning 2 1.67E-06 5.84E-04 %SLOCA SMALL LOCA IE IDENTIFIER 1.00E+00 1LPPMRHRA----A RHR PUMP A FAILSTO START DUE TO RANDOM FAULT 2.85E-03 1LPPMRHRB----A RHR PUMP B FAILS TO START DUE TO RANDOM FAULT 3 l.GOE-06 3.26E-02 %LOSP LOSS OF OFFSITE POWER IE IDENTIFIER 2.48E-04 NSCW CT SPRAY VALVES HV1668A & 69A FAILS TO OPEN DUE TO CCF 1SWMV1668A69ADCC 1.98E-01 RCPSL-182GPM RCP SEAL LEAK 182 GPM /PUMP 13 MIN AFTER SBO 4 1.44E-06 1.00E+OO %LONSCW LOSS OF NSCW IDENTIFIER 3.43E-04 1SWPM1234---&XCC NSCW PUMPS 1, 2, 3, & 4S PUMPS FAIL TO RUN (1 YEAR)- CCF 2.00E-02 OA-OSW-------H NSCW PUMP 1,2,3,4,5, OR GINITIATOR AND OPERATOR FAILS TO ESTABLISH 1 NSCW

-PUMP 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

5 1.39E-06 4.86E-04 %MLOCA MEDIUM LOCA IE IDENTIFIER l.OOE+OO lLPPMRHRA----A RHR PUMP A FAILSTO START DUE TO RANDOM FAULT 2.85E-03 lLPPMRHRB----A RHR PUMP B FAILS TO START DUE TO RANDOM FAULT E2-19 Risk Informed Analysis -C- Top 10 CDF Internal Events Cutsets, PM Case

  1. Cutset Event Inputs Description Prob. Prob.

6 1.12E-06 4.86E-04 %MLOCA MEDIUM LOCA IE IDENTIFIER 2.30E-03 OAR_HPML-----H OPERATOR FAILS TO ESTABLISH HIGH PRESSURE RECIRC- MLO 7 l.OSE-06 5.84E-04 %SLOCA SMALL LOCA IE IDENTIFIER l.OOE+OO lLPPMRHRA----A RHR PUMP A FAILSTO START DUE TO RANDOM FAULT l.BOE-03 1SWTS2-F04---F FAILURE OF TEMPERATURE SWITCH START LOGIC 8 1.03E-06 5.06E-02 %1SINJ INADVERTENT SIINJECTION IE IDENTIFIER 9.65E-05 1SWFN40RMORE- 4 OR MORE NSCW FANS FAIL TO START DUE TO COMMON CAUSE FAILURE ACC 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

9 1.01E-06 l.OOE+OO %LONSCW LOSS OF NSCW IDENTIFIER 4.80E-06 1SWPMALL----&XCC CCF AFFECTING ALL NSCWPS REGARDLESS OF DIFFERENT OP. HISTORIES {1YR) 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

10 9.06E-07 5.06E-02 %1SINJ INADVERTENT SIINJECTION IE IDENTIFIER 8.52E-OS 1ACSDU301302-FCC COMMON CAUSE FAILURE OF LOAD SEQUENCER 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

E2-20 Risk Informed Analysis -D- Top 10 LERF Cutsets, Baseline Case

  1. Cutset Event Inputs Description Pro b. Pro b.

1 1.93E-07 1.93E-07 %FIRE_A105-NO_ABNl MCR Abandonment Scenario- MCR2 Transients HVAC Fa- Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED 2 1.93E-07 1.93E-07 %FIRE_A105-JY_ABN1 MCR Abandonment Scenario- MCRl Transients HVAC Fa- Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED 3 1.31E-07 1.31E-07 %FIRE_A105-JY_ABN4 MCR Abandonment Scenario- MCRl MCB HVAC Normal- Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED 4 1.31E-07 1.31E-07 %FIRE_A105-JY_ABN7 MCR Abandonment Scenario- MCR2 MCB HVAC Normal- Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED 5 1.31E-07 1.31E-07 %FIRE_A105-NO_ABN4 MCR Abandonment Scenario- MCR2 MCB HVAC Normal- Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED 6 1.31E-07 1.31E-07 %FIRE_A105-NO_ABN7 MCR Abandonment Scenario- MCRl MCB HVAC Normal- Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED E2-21 Risk Informed Analysis -D- Top 10 LERF Cutsets, Baseline Case

  1. Cutset Event Inputs Description Pro b. Pro b.

7 6.50E-08 2.39E-04 %FIRE_1098-JD_B1 Train B Shutdown Panei1-1605-P5-SDB Fire- No Spr- Initiator 6.60E-01 1AFPMP4002--U_0.66 SPURIOUS OPERATION OF MDAFWP B 3.30E-01 1HPMVHV8438- CCP A&B DISCHAGRE INTERCONNECT MOV HV8438 PLUGS p 0.33 5.00E-03 CONSQ-SGTR-SSB PROBABILITY OF CONESEQ. SGTR GIVEN SSB l.OOE+OO L2LERF LARGE AND EARLY RELEASE 2.50E-01 SGTR1 SGTR IS IN SG 1 8 6.50E-08 2.39E-04 %FIRE_1098-JD_B1 Train B Shutdown Panei1-1605-P5-SDB Fire- No Spr- Initiator 6.60E-01 1AFPM P4002---U _0.66 SPURIOUS OPERATION OF MDAFWP B 3.30E-01 1HPMVHV8438-- CCP A&B DISCHAGRE INTERCONNECT MOV HV8438 PLUGS p 0.33 5.00E-03 CONSQ-SGTR-SSB PROBABILITY OF CONESEQ. SGTR GIVEN SSB l.OOE+OO L2LERF LARGE AND EARLY RELEASE 2.50E-01 SGTR4 SGTR IS IN SG 4 9 6.45E-08 6.45E-08 %FIRE_A105-JY_ABN3 MCR Abandonment Scenario- MCR1 Panels HVAC Normal-Initiator 1.00E+00 L2LERF LARGE AND EARLY RELEASE 1.00E+OO NO_BYPASS CONTAINMENT NOT BYPASSED 10 6.4SE-08 6.4SE-08 %FIRE_A105-NO_ABN6 MCR Abandonment Scenario- MCR1 Panels HVAC Normal-Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE 1.00E+OO NO_BYPASS CONTAINMENT NOT BYPASSED E2-22 Risk Informed Analysis -E - T op lOLERFCutsets, PMCase

  1. Cutset Event Inputs Description Pro b. Pro b.

1 8.36E-06 3.98E-05 %FIRE_A105-JY_L MCR Panel QPCP Fire - Initiator 1.00E+OO 1LPPMRHRA----A RHR PUMP A FAILSTO START DUE TO RANDOM FAULT 1.00E+OO L2LERF LARGE AND EARLY RELEASE 1.00E+OO NO_BYPASS CONTAINMENT NOT BYPASSED 2.10E-01 RCPSL-GT21GPM RCP SEAL LEAK GREATER THAN 21 GPM/RCP AFTER TOTAL LOSS OF SEAL CLG.

2 1.93E-07 1.93E-07 %FIRE_A105-NO_ABN1 MCR Abandonment Scenario- MCR2 Transients HVAC Fa -Initiator 1.00E+OO L2LERF LARGE AND EARLY RELEASE 1.00E+OO NO_BYPASS CONTAINMENT NOT BYPASSED 3 1.93E-07 1.93E-07 %FIRE_A105-JY_ABN1 MCR Abandonment Scenario- MCR1 Transients HVAC Fa -Initiator 1.00E+OO L2LERF LARGE AND EARLY RELEASE l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED 4 1.75E-07 2.39E-04 %FIRE_1098-JD_B1 Train B Shutdown Panei1-1605-P5-SDB Fire- No Spr- Initiator 1.00E+OO 1LPPMRHRA----A RHR PUMP A FAILSTO START DUE TO RANDOM FAULT 6.60E-01 1RCPORV0456A- PRESSURIZER PORV PV-0456A SPURIOUSLY OPENS DUE TO FIRE u 0.66 l.OOE+OO L2LERF LARGE AND EARLY RELEASE 1.11E-03 L2TEAR CONTAIN ISOL FAIL DUE TO PRE-EXISTING MAINT ERRORS, CRACKS, OR TEARS l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED 5 1.31E-07 1.31E-07 %FIRE_A105-JY_ABN4 MCR Abandonment Scenario- MCR1 MCB HVAC Normal-Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE 1.00E+OO NO_BYPASS CONTAINMENT NOT BYPASSED E2-23 Risk Informed Analysis -E - Top lOLERFCutsets, PMC ase 6 1.31E-07 1.31E-07 %FIRE_A105-JY_ABN7 MCR Abandonment Scenario- MCR2 MCB HVAC Normal- Initiator l.OOE+OO L2LERF LARGE AND EARLY RELEASE l.OOE+OO NO_BYPASS CONTAINMENT NOT BYPASSED 7 1.31E-07 1.31E-07 %FIRE_A105-NO_ABN4 MCR Abandonment Scenario- MCR2 MCB HVAC Normal- Initiator 1.00E+OO L2LERF LARGE AND EARLY RELEASE 1.00E+OO NO_BYPASS CONTAINMENT NOT BYPASSED 8 1.31E-07 1.31E-07 %FIRE_A105-NO_ABN7 MCR Abandonment Scenario- MCR1 MCB HVAC Normal- Initiator 1.00E+OO L2LERF LARGE AND EARLY RELEASE 1.00E+OO NO_BYPASS CONTAINMENT NOT BYPASSED 9 6.50E-08 2.39E-04 %FIRE_1098-JD_B1 Train B Shutdown Panei1-1605-P5-SDB Fire- No Spr- Initiator 6.60E-01 1AFPMP4002---U_0.66 SPURIOUS OPERATION OF MDAFWP B 3.30E-01 1HPMVHV8438-- CCP A&B DISCHAGRE INTERCONNECT MOV HV8438 PLUGS p 0.33 5.00E-03 CONSQ-SGTR-SSB PROBABILITY OF CONESEQ. SGTR GIVEN SSB 1.00E+OO L2LERF LARGE AND EARLY RELEASE 2.50E-01 SGTR1 SGTR IS IN SG 1 10 6.50E-08 2.39E-04 %FIRE_1098-JD_B1 Train B Shutdown Panei1-1605-P5-SDB Fire- No Spr -Initiator 6.60E-01 1AFPMP4002--U_0.66 SPURIOUS OPERATION OF MDAFWP B 3.30E-01 1HPMVHV8438-- CCP A&B DISCHAGRE INTERCONNECT MOV HV8438 PLUGS p 0.33 5.00E-03 CONSQ-SGTR-SSB PROBABILITY OF CONESEQ. SGTR GIVEN SSB l.OOE+OO L2LERF LARGE AND EARLY RELEASE 2.50E-01 SGTR4 SGTR IS IN SG 4 E2-24

Vogtle Electric Generating Plant Request to Revise Technical Specifications LCO 3.5.2 for a One-Time Change to_Support a Unit 1 Residual Heat Removal Pump Motor Replacement Enclosure 3 Marked-Up Technical Specifications Page

ECCS- Operating 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) NOTE A one-time only change 3.5.2 ECCS - Operating of the Completion Time to 7 days is permitted for the 1A RHR pump LCO 3.5.2 Two ECCS trains shall be OPERABLE. motor replacement during Vogtle Unit 1, Cycle 19. The APPLICABILITY: MODES 1, 2, and 3. increased Completion Time is applicable only

NOTE------- to the 1A RHR pump.

In MODE 3, either residual heat removal pump to coldl e s injection flow path may be isolated by closing the isolation valve t perform pressure isolation valve testing per SR 3.4.14.1.

ACTIONS CONDITION REQUIRED ACTION I

COMPf ETION TIME A. One or more trains inoperable.

A.1 Restore train(s) to OPERABLE status.

j 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> At least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. AND B.2 Be in MODE4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Vogtle Units 1 and 2 3.5.2-1 Amendment No. ~ (Unit 1)

Amendment No. ~ (Unit 2)

Vogtle Electric Generating Plant Request to Revise Technical Specifications LCO 3.5.2 for a One-Time Change to_Support a Unit 1 Residual Heat Removal Pump Motor Replacement Enclosure 4 Clean-Typed Technical Specifications Page

ECCS- Operating 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS - Operating LCO 3.5.2 Two ECCS trains shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

NOTE--------- -----------

In MODE 3, either residual heat removal pump to cold legs injection flow path may be isolated by closing the isolation valve to perform pressure isolation valve testing per SR 3.4.14.1.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more trains A.1 Restore train(s) to -----NOTE-----

inoperable. OPERABLE status. A one-time only change of the AND Completion Time to 7 days is permitted for At least 100% of the the 1A RHR pump ECCS flow equivalent to motor replacement a single OPERABLE during Vogtle Unit 1, ECCS train available. Cycle 19. The increased Completion Time is applicable only to the 1A RHR pump.

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. AND B.2 Be in MODE4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Vogtle Units 1 and 2 3.5.2-1 Amendment No. (Unit 1)

Amendment No. (Unit 2)

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