ML13151A023

Oconee Nuclear Station, Units 1, 2 and 3, Additional Information Regarding License Amendment Request for Temporary Technical Specification Change to Add a Required Action Completion Time for One Keowee Hydro Unit Inoperable for Generator Fi

ML13151A023
Person / Time
Site:	Oconee
Issue date:	05/28/2013
From:	Batson S L Duke Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML13151A023 (21)

Text

ENDUKE SoGY L.Baton ENERGY, Vice President Oconee Nuclear Station Duke Energy ONOI VP j 7800 Rochester Hwy 10 CFR 50.90 Seneca, SC 29672 o: 864.873.3274 May 28, 2013 f 864.873.4208 Scott.Batson@duke-energy.com U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

Subject:

Duke Energy Carolinas, LLC Oconee Nuclear Station (ONS), Units 1, 2, and 3 Docket Numbers 50-269, 50-270, and 50-287 Additional Information Regarding License Amendment Request for Temporary Technical Specification Change to Add a Required Action Completion Time for One Keowee Hydro Unit Inoperable for Generator Field Pole Rewinds License Amendment Request (LAR) No. 2012-01, Supplement 2 On June 27, 2012, Duke Energy Carolinas, LLC (Duke Energy) submitted a License Amendment Request (LAR) requesting the Nuclear Regulatory Commission (NRC) approve a Technical Specification (TS) change that adds a temporary Completion Time to TS 3.8.1 Required Action (RA) C.2.2.5 to allow time to perform major maintenance on a Keowee Hydro Unit (KHU). By letter dated November 13, 2012, the NRC requested Duke Energy to submit additional information associated with the LAR. Duke Energy responded to this request by letter dated December 14, 2012. By letter dated April 12, 2013, the NRC issued another request for additional information.

The enclosure provides the requested information.

The attachment provides a list of regulatory commitments associated with this letter. If there are any additional questions, please contact Boyd Shingleton, ONS Regulatory Affairs, at (864) 873-4716.I declare under penalty of perjury that the foregoing is true and correct. Executed on May 28, 2013.Sincerely, Scott L. Batson, Vice President Oconee Nuclear Station

Enclosure:

Response to NRC Request for Additional Information

Attachment:

List of Regulatory Commitments www.duke-energy.com A¢rt&

Nuclear Regulatory Commission License Amendment Request No. 2012-01, Supplement 2 May 28, 2013 Page 2 cc w/Enclosure/Attachment Mr. Victor McCree, Regional Administrator U. S. Nuclear Regulatory Commission

-Region 11 Marquis One Tower 245 Peachtree Center Ave., NE, Suite 1200 Atlanta, GA 30303-1257 Mr. John Boska, Senior Project Manager (by electronic mail only)Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission 11555 Rockville Pike Mail Stop O-8G9A Rockville, MD 20852 Mr. Ed Crowe Senior Resident Inspector Oconee Nuclear Site Ms. Susan E. Jenkins, Manager Radioactive

& Infectious Waste Management Division of Waste Management South Carolina Department of Health and Environmental Control 2600 Bull St.Columbia, SC 29201 ENCLOSURE Duke Energy Response to NRC Request for Additional Information (RAI)

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 23, 2013 Page 1 EEEB RAI 1: In "Response to staff RAI 2" in letter dated December 14, 2012, the licensee stated that they do not need to restrict performance of the KHU [Keowee Hydro Unit] pole rewind work in the tornado months because the expected frequency of loss of offsite power (LOOP) events as a result of severe weather is less than the annual average.Provide expected frequency of LOOP events for each month of a year. Discuss the protocol and coordination which will be established with the grid operator during the KHU outage.Duke Energy Response: The purpose of the scheduling restriction in the previous Keowee amendment (issued in August 5, 2004, ADAMS Accession No. ML042290546) pertained to a request for a one-time extension of the dual KHU Allowed Outage Time (AOT), which is in contrast to the current request to extend the single KHU AOT. The tornado risk concern for a dual KHU outage is that a tornado strike could damage both the switchyard and the 100kV Fant line at the same time that the Keowee underground power supply is unavailable.

This risk is mitigated primarily by risk management plans that require a clear weather forecast and preclude entering the dual KHU outage phase if the potential for severe weather exists during the outage window. In that case, increasing the length of the dual KHU portion of outage increased the potential for severe weather during the outage window due to uncertainty of the weather forecast.

Thus, it was reasonable to restrict the 2004/2005 Keowee outages to the months of lowest tornado activity to offset the uncertainty and risk associated with extending the dual KHU outage window.The months of highest tornado activity for the Oconee region are March, April, and May. The Oconee Probabilistic Risk Assessment (PRA) estimates the average annual tornado strike frequency to be 1.4E-04/Rx-Yr.

When the frequency data is partitioned, the Oconee tornado strike frequency from March -May is estimated to be 3.5E-04/Rx-Yr representing a factor of 2.5 increase over the annual average value. Outside of these months the tornado frequency is estimated to 5.8E-05/Rx-Yr representing a factor of approximately 2.4 decrease from the annual average value.With respect to extending the Completion Time for one inoperable KHU, the potential increase in tornado frequency during the spring months has very little impact on overall plant risk. This is because the available unit is aligned to the Keowee underground path and the unit being removed from service would otherwise be aligned to the Keowee overhead path. The PRA assumes that the Keowee overhead path is unavailable if a tornado causes a LOOP by damaging the switchyard or transmission lines.The more relevant concern related to the planned Keowee outages are more frequent types of events that have caused LOOP events in the United States (US) nuclear industry.

In the Oconee PRA, the overall LOOP frequency is estimated to be 1.87E-02/Rx-Yr.

This frequency is dominated by switchyard-centered events that do not have any known seasonal variation.

In general, there is insufficient LOOP data to reliably predict how much the LOOP frequency may vary month by month. However, qualitatively it is noted that there is potentially some seasonal variation with License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 2 grid-related LOOPs being more likely during the summer months when electrical loads are at peak levels. This is not considered to be a significant concern for Oconee for the following reasons.First, the industry grid failures that have occurred are associated with regions of the country where there was low operating margin and susceptibility to grid-related LOOPs. In contrast, the Duke Energy electrical system and the Southeastern US region are generally considered to have higher reliability relative to the US average. Secondly, Oconee has a strong defense-in-depth for mitigation of grid-related LOOP events (refer to the response to EEEB RAI 7 below). Third, the risk management plan for the Keowee outages includes restrictions on switchyard maintenance that decrease the likelihood of a LOOP by reducing the exposure to potential human errors or other problems could cause a LOOP during the outage period. With these factors taken together, the Oconee LOOP frequency is not expected to vary significantly throughout the year and the likelihood of a LOOP during a KHU outage period should not be higher than the annual average frequency.

During the KHU outages, the protocol for work coordination and communication will be consistent with that established in the Nuclear Switchyard Interface agreement and the Nuclear Switchyard Operating Guidelines currently in place. Oconee will minimize risk through proper coordination between the plant and the Transmission Control Center (TCC). Transmission Coordinators at the TCC routinely communicate transmission matters such as system configurations, work at other sites, line switching and work being performed by site personnel that may have an effect on the nuclear plant. Transmission communicates to the Oconee Switchyard Coordinator or designee any planned operations of site equipment that could have an impact at ONS. Notification of planned activities requires a fourteen week lead-time.

This lead-time is necessary for risk analysis on activities that may impact reliability of offsite power to ONS. Similarly, the Oconee Switchyard Coordinator or Work Control personnel notify the TCC of plant risk changes that increase the plant's sensitivity to offsite power status. This notification will be a prerequisite in the Critical Activity Plan for the planned maintenance activity.

As part of the Critical Activity Plan for this work activity, the Work Control Center is to notify the TCC and the System Operating Center to take action to ensure grid reliability and minimize risks (e.g., minimize non-critical maintenance work affecting ONS ties in surrounding power paths and substations).

See the response to EEEB RAI 7 for additional details on the Critical Activity Plan.EEEB RAI 2: In "Response to staff RAI 3" in letter dated December 14, 2012, the licensee stated that they will ensure that pole-rewind work would be scheduled so that there is no impact on or conflict with protected service water (PSW) related work and that there is no adverse impact on the availability of any safe shutdown systems.Provide an estimated schedule for PSW work. Provide the basis for not providing a regulatory commitment in the LAR to ensure that there would be no impact or conflict between the pole-rewind work and PSW related work, and that there would be no adverse impact on the availability of any safe shutdown systems.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 3 Duke Energy Response: The approximate 14 day KHU outage required to tie-in Keowee Emergency Power to the Protected Service Water System is scheduled for KHU-2 in July 2013 and KHU-1 in September 2013. The approximate 75 day generator pole rewind outage is scheduled for KHU-1 from January -March 2014 and KHU-2 from July -September 2014. As scheduled, these work activities clearly do not impact or conflict with each other. Should this schedule change, Duke Energy will take the necessary steps to ensure the PSW tie-in work and the generator pole rewind work will not impact or conflict with each other. This does not preclude performing the work concurrently.

This is a regulatory commitment.

In addition to the tie-in of Keowee Emergency Power to the PSW system, other major PSW work activities and their committed completion dates were provided in Duke Energy letter dated March 11, 2013. Some of this work will be conducted during the extended KHU outages. As such, the unavailability of the KHU will be factored into PSW and other station work scheduled during the extended KHU outages using established risk management processes.

During schedule development, Work Control personnel use risk management screening criteria to identify any scheduled activities that require increased risk management controls.

Electronic Risk Assessment Tool results of the proposed schedule are used to identify PRA significant combinations of out of service equipment and risk management actions, developed in accordance with industry guidelines, implemented where appropriate.

Additionally, the Technical Specification (TS) required action of energizing both standby buses from LCT via isolated power path ensure there is no adverse impact on the availability of any safe shutdown systems.EEEB RAI 3: In "Response to staff RAI 6," in letter dated December 14, 2012, the licensee stated that between 2007 through 2012, Lee Combustion Turbine (LCT) 7C failed twice and LCT 8C failed 6 times, and each one resulted in Maintenance Rule Functional Failure (MRFF).1. Confirm that failures in LCTs are reviewed for common cause if the identical components are used in both LCTs. In particular, discuss whether corrective actions were taken on both LCTs when the LCT 7C (August 19, 2007) failure occurred due to a faulty micro-switch, and the LCT 8C (July 28, 2011) failure occurred due to a faulty servo-control I/O module.2. Are there any repetitive MRFF for LCT system? Provide a discussion of preventive maintenance and performance or condition monitoring actions taken in accordance with Title 10 of the Code of Federal Regulations, Section 50.65.Duke Energy Response 1. Failures in the LCTs are reviewed to consider the potential extent of condition.

Programmatic controls for the LCTs are warranted to ensure availability and reliability are maintained.

As such, the LCTs are included in the Selected Licensee Commitments (SLC) Manual and are subject to formal functionality assessments.

Duke Energy Nuclear System Directive (NSD)203, Operability/Functionality, provides guidance on functionality assessments consistent with the guidance provided in Regulatory Issue Summary (RIS) 2005-20, Revision 1. Per Duke Energy Nuclear Site Directive (NSD) 203, the formal functionality assessment content License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 4 includes a required extent of condition section which considers other components, trains, systems, or units affected by the failure. The two specific failures identified in EEEB RAI 3 Item 1 were reviewed for common cause/extent of condition if the same components were used in both LCTs.August 19, 2007 Failure LCT failed to start (8/19/07) due to a faulty micro-switch.

The following corrective actions were taken:* Replaced micro-switches on applicable in-service LCT 7C and 8C valves, as well as in-stock valves.* Additionally, these components were monitored after installation to ensure no operational issues* Bi-monthly preventive maintenance activities (PMs) are being performed to proactively identify a degrading switch prior to failure.July 28, 2011 Failure LCT 8C tripped while generating to the grid (7/28/11) due to a failure of a faulty servo-control I/O module. An extent of condition evaluation was performed to ensure the same issue was not a concern on the 7C Combustion Turbine. The problem was determined to be limited to the Input/output (1/O) module on the 8C Combustion Turbine and that component was replaced.2. There have not been any Repetitive MRFFs on the LCT system. The LCTs are included in the ONS Maintenance Rule program. This program tracks unavailability and reliability of the LCTs. Preventive maintenance and performance monitoring are performed on the LCTs to ensure continued equipment reliability.

Some of the PMs/Monitoring include:* An annual major turbine outage" A major 5 year generator outage, although other smaller electrical and generator maintenance PMs are performed on more frequent basis" Annual Black Start test* Daily Operator rounds* Daily phone call with Oconee Operations Control Room for updates on status, equipment concerns* Selected License Commitment (SLC) 16.8.6, Lee/Central Alternate Power System, is used to log and track the time the LCTs are not available to energize the Oconee Standby Buses. The SLC Commitment requires two LCTs be available for supplying power to the Oconee Standby Buses through a separated 100 kV power path within one hour of a loss of both On-Site Emergency Power Paths. Requirements for energizing the Oconee Standby Buses are found in TS.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 5 EEEB RAI 4 Note 1 for Technical Specification (TS) 3.8.1 Required Action C2.2.5 proposed Completion Time states, "No discretionary maintenance or testing allowed on SSF [Standby Shutdown Facility], EFW [Emergency Feedwater]

and essential AC [alternating current] Power System." Explain the term "essential AC Power System." Duke Energy Response The essential AC Power System encompasses equipment and risk significant systems associated with normal AC power availability as well as offsite power. Oconee has multiple available sources of electrical power to an ONS unit. These include the following:

1. The Oconee Unit Generator to Auxiliary Transformer (1T, 2T, 3T)2. 230kV Switchyard to Startup Transformer (CT1, CT2, CT3)3. Keowee Overhead Power Path through PCB-9 4. Keowee Underground Power Path through CT-4 5. Lee Steam Station through CT-5 EEEB RAI 5 In a presentation dated December 16, 2003 (ADAMS Accession No. ML033520190), for an earlier LAR dated August 22, 2002, for the Keowee Hydro Units maintenance outage, the licensee discussed the use of temporary diesel generators, during the maintenance period. The use of temporary alternate AC power sources, to enable each unit to reach and maintain cold shutdown, is consistent with NRC Electrical Branch Technical Position 8-8 (ADAMS Accession No.ML113640138) during extended planned outage periods of station emergency power. Given the questionable reliability history of the Lee Combustion Turbines and the susceptibility of the overhead transmission lines to severe weather events, explain why the current proposed one-time 75-day Keowee hydro unit maintenance outage does not include the use of temporary diesel generators.

Duke Energy Response The Lee Combustion Turbines referenced in the 2002 LAR have been replaced.

The new LCTs, which began commercial operation in January 2007, have been extremely reliable.

Below is a calculation of the reliability of the LCTs based on number of starts versus the number of failures.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 6 LCT RELIABILITY (6YRS)The calculation of the LCT Reliability is depicted below: Baseline Data (1/2007 -3/2013)Total LCT Start/Load Run Demands for 7C 370 Total LCT Start/Load Run Demands for 8C 382 RELIABILITY CALCULATION:

Reliability

= 1 -(Total Failures / Total Start (Load Run) Demands)Total Start/Load Run Demands Total Failures Reliability LCT 370 2 0.9946 (99.5%)7C LCT 382 6 0.9843 (98.4%)8C For the 2002 LAR, Duke Energy evaluated the feasibility of using temporary diesel generators (DGs) during only the dual KHU outage portions of the extended single KHU outage. There was an NRC Request for Additional Information (RAI) question associated with the diesel generator (DG) feasibility study during the August 22, 2002, LAR review. The RAI and the Duke Energy response (February 4, 2004) are re-stated at the end of this response.

In that LAR, Duke Energy requested extensions to the Completion Times for one KHU inoperable and for two KHUs inoperable.

The currently proposed one-time 75-day Completion Time to support the KHU generator pole rewind work for each KHU does not require dual KHU outage time past what is currently allowed by the 60 hour6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> Completion of TS 3.8.1 Required Action H.1.Asstated in the earlier RAI response, Duke Energy discussed the feasibility of using temporary DGs during a December 16, 2003, meeting with the NRC as documented in ADAMS Accession No. ML033520190.

In follow-up to that meeting, Duke Energy advised the NRC that temporary DGs were not feasible and would not be provided.

Duke Energy documented this response by letter dated December 18, 2003, and later in response to a specific RAI (Duke Energy letter dated February 4, 2004). Ultimately, the NRC did not require temporary DGs to be provided.

Duke Energy's response to the 2002 LAR Submittal RAI, which concluded that the use of temporary DGs (and other AC backup options) was not feasible, remains valid.During the extended Completion Time for one KHU inoperable and aligned to the overhead power path, and during time periods when both KHUs are inoperable, one of the two LCTs is required by TS 3.8.1 to be energizing both standby buses at ONS. The LCTs are permanent, alternate AC power sources (only one is required to provide all shutdown loads for all three units and maintain each unit in cold shutdown) that are consistent with BTP 8-8.During the extended single unit outage, the remaining operable KHU will be available to provide emergency power to the ONS via the underground or overhead power path. The underground path is not susceptible to severe weather events. Prior to taking both KHUs out of service, the weather forecast will be checked to confirm no severe weather is forecast for the period of the dual KHU outage. Refer to Duke Energy's response to EEEB RAI 7 below.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 7 One failure of the Lee overhead path due to severe weather has been observed over the past 6 years. Duke Energy maintains the overhead path to ensure high reliability since the LCT is a backup emergency power source. Maintenance Rule Risk Assessment and Unavailability monitoring of the 100 kV overhead path from the LCT is required by ONS SLC 16.8.6.Susceptibility of the overhead transmission lines to severe weather events is addressed in Duke Energy's response to EEEB RAI 7 below.The following is restated from TSC-2002 Supplement 2 dated February 4, 2004: RAI 7: Provide a discussion of the DG feasibility study used to evaluate the feasibility of installing temporary DGs during the dual KHU outage portions of each Keowee Refurbishment Outage.Response:

During the December 16, 2003 meeting between NRC and Duke Energy Corporation, Duke presented a feasibility study that was performed to determine the potential benefits of providing backup power during the dual KHU outage portion of the Keowee Refurbishment Outage for each Keowee unit. Three mitigation strategies were considered using temporary diesel generators (DGs) to power: 1) normal plant safe shutdown loads, 2) the station Auxiliary Service Water (ASW) switchgear, or 3) the Standby Shutdown Facility (SSF). The feasibility study assumed Keowee was in a dual unit outage and the occurrence of a three unit Loss of Offsite Power (LOOP) caused by a weather related event resulting in a loss of the Oconee switch yard, loss of the Lee CT dedicated line, and a loss of the Jocassee dedicated line. The study assumes the temporary DGs would be required to supply power for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.The feasibility of the mitigation strategies and implementation options were evaluated using the following evaluation criteria:

1) operator burden, 2) feasibility of implementation, 3) risk to plant equipment, 4) recovery capability, 5) cost, 6) security measures, 7) environmental impacts, and 8)overall risk benefit.Temporary DGs to power normal safe shutdown loads This strategy involves powering safe shutdown loads for each unit through main feeder buses via a connection between transformer CT-5 and the SL breakers.

Station LOOP (normal plant safe shutdown) loads would be approximately 10, 000 kW requiring a minimum of six package DGs.These LOOP loads include High Pressure Injection (HPI), Low Pressure Service Water (LPSW), Emergency Feedwater (EFW), and Essential Siphon Vacuum (ESV) pumps, as well as non load shed load centers and motor control centers, and the Control Room (CR) chiller compressor.

Several load sequencing issues were identified:

1) Oconee units do not have sequencers, all emergency loads are block loaded at one time waiting for power to arrive, 2) package DGs cannot accept unit block loading as Duke's larger Keowee, Lee, and Jocassee units can, so manual stripping and sequencing of loads would be required, 3) each unit's Emergency Power Switching Logic (EPSL) logic breakers (S breakers) would have to be placed in manual to prevent block automatic loading onto the standby bus once energized by the temporary DGs, 4) individual loads would have to be manually load shed and taken to manual to prevent automatically starting and overloading the temporary DGs when power is restored to a units main feeder bus, 5) each CR[Control Room] would be performing these activities locally in the CR and remotely in a "dark" plant, and 6) loads started from the temporary DGs would need to be coordinated between three CRs to prevent overloading and tripping the DGs. DG and fuel staging were a problem due to the License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 8 number of diesels and the fuel supply required for a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> run. Additionally, this strategy presented additional environmental concerns due to the additional fuel that would be on-site during the Keowee Refurbishment Outage. The operator actions described above that would be required to implement this strategy were considered complex when coordinated between three Control Rooms to prevent overloading and tripping the DGs. This option was deemed to be costly and complex. Duke's risk evaluation determined that this option would only provide a small risk benefit. As such, Duke concluded this option was not feasible.Power the ASW Switchgear with Temporary DGs This strategy involves powering the station ASW pump and one HPI pump for each unit through the ASW switchgear and vital battery charger via each unit's stripped main feeder bus breakers.Station load would be approximately 3000 kW requiring three package DGs. The DGs would be connected between CT-5 and the SL breakers.

This option would require depressurizing the steam generators (SGs) since the ASW pump is a low pressure pump (after normal turbine driven emergency feedwater is exhausted).

Steam and feedwater operations are manual, requiring multiple operator actions in each penetration room and at ASW switchgear for each unit. Each unit's EPSL S breakers would have to be placed in manual to prevent automatic loading of normal emergency loads on the temporary DGs when powering the standby bus and ASW switchgear.

Load shedding or stripping the 4 kV buses and 600 V buses would be needed to align only one charger for each unit. This adds complexity due to the different places the operators would have to go to strip the buses to align the individual selected load. Implementing this strategy would require complex operations procedures and intricate, coordinated operator actions between three CRs.This design was not considered well suited for three unit mitigation.

This strategy poses the same environmental concerns as the previous strategy.

This option was slightly less expensive to implement.

Duke's risk evaluation determined that this option would only provide a small risk benefit. Considering the cost and complexity and the small risk benefit afforded by implementing the option, Duke concluded the option was not feasible.Power the SSF with Temporary DGs This mitigation strategy would involve replacing the generation that would normally be provided by the SSF DG. The SSF load is approximately 3500 kW requiring three package DGs. Two options were considered:

1) powering the SSF via DGs connected directly to SSF Switchgear OTS1, or 2)powering the SSF via DGs connected between CT-5 and SL breakers with power routed through the plant's normal SSF connection (4160 V standby bus and Unit 2 main feeder bus to SSF switchgear OTS1). The first option would power the SSF via a direct connection to SSF switchgear OTS1. The package DGs would be located near transformer CT-5 and make use of the existing CT-5 cable trench to route power to the SSF. The SSF auxiliary distribution switchgear, OTS1, has no spare compartments available for this new incoming power feed. Thus, this option would require a modification to the safety related switchgear to implement.

The modification would require approximately 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of SSF unavailability to implement.

This option would require purchase of a safety related breaker or disconnect switch for a switchgear safety/non-safety isolation.

The lead time for new safety related equipment will not meet the current outage schedule.

The space in the SSF equipment room is limited so the new breaker/disconnect switch would have to be located in the upstairs HVAC room. The second option would power the SSF via DGs connected to the CT-5 switching station with routing via its normal power path (main feeder bus 2 on Unit 2). There are load shed issues to line up the electrical system breakers to selectively feed the SSF OTS1 Switchgear.

Each unit's EPSL logic License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 9 would have to be placed in manual to prevent automatically loading. Individual loads would have to be placed in manual to prevent automatically overloading the temporary DGs when power is applied to a unit's main feeder bus. The Unit 2 4 kV switchgear breaker on main feeder bus 2 would have to be manually tripped to keep from overloading the temporary DGs with normal 4 kV loads. Also, the interlocking logic on this normal SSF power feeder source breaker would have to be disabled to allow the breaker to close with a LOOP on Unit 2. Implementing this strategy is complex because of the operator actions required both in the plant and in the SSF, and the short period of time allowed for successful implementation due to the limited capacity of the SSF Reactor Coolant Makeup Pump. This strategy poses the same environmental concerns as the previous two strategies.

The option of directly connecting temporary DGs to the SSF was the most expensive option considered.

The indirect connection was estimated at about half the cost of the direct connection.

However the additional complexity due to the time-constrained operator actions to align the plant and the SSF were very undesirable.

Duke's risk evaluation determined that this option would only provide a small risk benefit. Considering the cost and complexity and the small risk benefit afforded by implementing either option, Duke concluded this mitigation strategy was not feasible.Summary During the December 16, 2003 meeting, Duke presented the risk benefits associated with each mitigation strategy.

As shown in Attachment 1 [not included here], the cumulative core damage probability (CCDP) for each proposed 62 day Keowee Refurbishment Outage is 4.4E-07. The first strategy (connect plant electrical distribution system to power unit safe shutdown loads) would change the CCDP to approximately

-7E-07. The second strategy (connect to ASW Switchgear) resulted in a CCDP of approximately

-5E-07, while the third strategy (directly or indirectly connect to the SSF) resulted in a CCDP of 3. 8E-07. In summary, none of the strategies provided a significant risk benefit. Based on the cost and complexity of implementing the mitigation strategies and the slight risk benefit associated with implementing, Duke concluded that none were feasible.The NRC attendees agreed with this conclusion during the meeting. Duke documented this understanding in a letter dated December 18, 2003.From Duke Energy letter dated December 18, 2013 Duke Energy Corporation (Duke) met with NRC personnel on December 16, 2003, to discuss our request to temporarily extend the allowed outage times (AO Ts) for inoperable Keowee Hydro Units (KHUs). Duke submitted a license amendment request to temporarily extend the Technical Specification (TS) AOTs for one or two inoperable Keowee Hydro Units (KHUs) on August 22, 2002 (and supplemented on September 12, 2003) to support planned Keowee maintenance activities.

During several recent conference calls, the NRC had requested Duke to evaluate the feasibility of installing temporary diesel generators (DGs) as an additional risk reduction measure to support the proposed license amendment.

As part of that feasibility study, Duke also evaluated the risk benefits associated with installing DGs. Duke presented the results of that feasibility study during the meeting. Based on dialogue during the meeting, Duke concludes that NRC is in agreement that adding temporary DGs provides minimal risk benefits and as a result does not intend to further pursue installing DGs.EEEB RAI 6 License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 10 EEEB RAI 6 Provide a summary of all the loads that are required to be connected to the SSF diesel to achieve safe shutdown condition.

Explain whether the SSF diesel has adequate capacity to bring all three Oconee units to safe shutdown condition simultaneously.

Duke Energy Response The Standby Shutdown Facility (SSF) is designed as a standby system for use under certain emergency conditions.

The system provides additional "defense in-depth" protection for the health and safety of the public by serving as a backup to existing safety systems. The SSF serves as a backup for existing safety systems to provide an alternate and independent means to achieve and maintain one, two, or three Oconee units in MODE 3 with average RCS temperature

>_ 525 0 F (unless the initiating event causes the unit to be driven to a lower temperature) for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a fire event, a turbine building flood, sabotage, or tornado missile events and for station blackout (SBO)coping for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This is accomplished by re-establishing and maintaining Reactor Coolant Pump Seal cooling; assuring natural circulation and core cooling by maintaining the primary coolant system filled to a sufficient level in the pressurizer while maintaining sufficient secondary side cooling water; and maintaining the reactor subcritical by isolating all sources of Reactor Coolant System (RCS) addition except for the Reactor Coolant Makeup System which supplies makeup of a sufficient boron concentration.

The main components of the SSF are the SSF Auxiliary Service Water (ASW) System, SSF Portable Pumping System, SSF Reactor Coolant (RC) Makeup System, SSF Power System, and SSF Instrumentation.

The SSF Power System provides electrical isolation of SSF equipment from non-SSF equipment.

The SSF Power System includes 4160 VAC, 600 VAC, 208 VAC, 120 VAC and 125 VDC power.It consists of switchgear, a load center, motor control centers, panelboards, remote starters, batteries, battery chargers, inverters, a diesel generator (DG), relays, control devices, and interconnecting cable supplying the appropriate loads. The SSF DG is capable of powering all SSF equipment required for safe shutdown as described above.EEEB RAI 7 Provide a discussion of maintaining plant safety and defense in-depth of onsite emergency power system when performing this maintenance work with all three units at power versus units at shutdown condition.

Duke Energy Response ONS assesses and manages the increase in risk that may result from the proposed maintenance activities in accordance with 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. By limiting the performance of discretionary maintenance and testing during the extended maintenance period, there is a reduction in at-power risk with one KHU out of service compared to baseline plant risk. Defense-in-depth (DID) is maintained through License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 11 a number of different power sources and alternate means of accident mitigation as described below. A higher level of DID is available for at-power operations because of the ability to establish steam generator cooling using either the Standby Shutdown Facility (SSF) or the Turbine-Driven Emergency Feedwater Pump (TDEFWP).

These alternate means of core cooling are not available below MODE 3.Defense-in-Depth By LOOP Initiating Event Category For grid-related events" A Keowee unit aligned to the underground path to CT4 (except for dual-unit outage portion)" A dedicated 100 kV line electrically separated from the transmission system (system grid)" A Lee Combustion Turbine (LCT) already running and energizing the standby buses* One additional LCT available, which can provide the necessary power* SSF remains available as an alternate shutdown method (not available below MODE 3)* TDEFWP remains available as an alternate shutdown method with limitations on runtime for multi-unit LOOP events (not available below MODE 3).For switchyard centered events* A Keowee unit aligned to the underground path to CT4 (except for dual-unit outage portion)" A dedicated 100 kV line electrically separated from the transmission system (system grid)" A Lee Combustion Turbine (LCT) already running and energizing the standby buses* One additional LCT available, which can provide the necessary power* SSF remains available as an alternate shutdown method (not available below MODE 3)* TDEFWP remains available as an alternate shutdown method with limitations on runtime for multi-unit LOOP events (not available below MODE 3).For weather-related events that take out switchyard or loss of all incoming power lines** A Keowee unit aligned to the underground path to CT4 (except for dual-unit outage portion)S SSF remains available as an alternate shutdown method (not available below MODE 3)* TDEFWP remains available as an alternate shutdown method with limitations on runtime for multi-unit LOOP events (not available below MODE 3).*Note: The likelihood of having a weather event that takes out all power lines is low. There are 11 offsite power circuits that come in from different directions into the Oconee 230kV and 525kV switchyards and an additional 100kV circuit directly to Transformer CT5. Thus, it is not likely that Oconee would lose power from all the lines at the same time.Additionally, per Duke Energy's Risk Management Process, a Critical Activity Plan will be written for this extended outage for risk mitigation purposes.

Critical Activity Plans are reviewed and approved by the Plant Operations Review Committee prior to implementation.

This plan will include similar risk mitigation strategies to those that are currently used in the Critical Activity Plans for scheduled Dual Unit Outages. As an example, applicable excerpts from the Critical Activity Plan that was used for the most recent Dual Unit outage are copied below. As seen below, the Critical Activity Plan addresses multiple risk and mitigation strategies, including severe weather, and states that the weather forecast will be reviewed prior to entering a Dual Unit outage condition and will also be monitored during the outage window to determine whether work will continue based on changing weather conditions.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 12 Keowee Hydro Station February 2013 Dual Outage

Description:

During 13WEEK09 Keowee Units #1 and #2, and both the Overhead and Underground Power Paths will be unavailable and inoperable due to the Keowee Hydro Units being simultaneously un-watered for planned maintenance.

The total duration of the Keowee Hydro Station (KHS) dual outage is 47 hours5.439815e-4 days <br />0.0131 hours <br />7.771164e-5 weeks <br />1.78835e-5 months <br />. Of this total duration an ORANGE ERA T condition will exist for a period of 42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br /> followed by a GREEN ERA T condition of 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> while the operability checks and securing from back-up power alignments are being performed.

The duration of this evolution will exceed 33% of the Technical Specification Action Limits. Prior to outage Lee Combustion Turbine (LCT) will energize Standby Buses per TS 3.8.1.Two key risks of this evolution are extended duration of the unavailability of both Keowee units and the challenges that would exist due to the loss of the alternate Emergency Power Path from Lee Combustion Turbines (LCTs).Risk Mitigation 1.A. Extended unavailability due to mismanagement of Critical Path activities.

1.B. Extended unavailability due to emergent issues (not planned)1. C. Extended unavailability due to restoration delays.l.A. 1 The Keowee OCC will be staffed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during this evolution to ensure critical path activities are managed and supported.

l.A. 2 Hands on verification of parts availability and procedure walk-downs and validations.

1.A.3 Readiness reviews performed for Maintenance tasks at T-1 prior to start of Dual Unit Outage and LCO entry.1.A.4 Just in Time Training provided to KHS Operations in regards to the use of OP/O/A/2000/061"KHS Back-up Auxiliary Power Source".1.B. I Unit Threat Response Team pre-identified to be activated by OSM/ CAP Manager as necessary.

1. C. I KHS Operations shall identify Restoration Coordinators providing 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage.1. C. 2 ONS Operations shall have dedicated SROs for restoration.

1. C.3 KHS shall have one additional NEO assigned per shift 2.A. Loss of Backup Power to ONS from Lee Steam Station 2. A. I Additional LCT available for startup.2.A.2 Central Switchyard restricted access and LCTs and LSS Swyd.2.A.3 Evaluate establishing Unit Threat Response License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 13 Team upon complete loss of LCP path.2.A.4 Verify NO outstanding corrective work orders affecting LCT operation.

2. B. Complete loss of offsite power 2. B. 1 ONS Operations protect 230 KV Switchyard and CT-5.2.B.2 TCC restrict work and access in surrounding power paths and substations.

2. B. 3 No Orange grid condition exist or planned 3.A. Outside influences (Severe 3.A. 1 Review of weather forecast prior to beginning weather) evolution.

The OCC Outage Manager and OSM will make the decision for continuing based on forecasts and criteria in Conditional Measure #1.3A. 2 Monitoring of forecast each shift and updated at OCC shift meetings.

Based on criteria in Conditional Measure #1, the decision will be made to continue the outage or address restoration of the Keowee Hydro Units.3.A. 3 Assessment of changing weather conditions using criteria in Conditional Measures # 1 (Criteria to be used in Risk Category 3 (Outside Influences:

Severe Weather) mirror the criteria used in AP/O/A/1 700/006, 'Natural Disaster' to include tornado warnings, tornado watches, severe thunderstorm warnings, high wind warnings, and Condition

'A' or 'B' scenarios associated with the Intake Canal or Jocassee Dam).4.A. Emergent issues with ONS 4.A. 1 0CC Outage Manager and OSM will assess Protected Equipment that reduces issue and determine path to restore protected defense in depth. equipment.

4.A.2 Evaluate establishing Unit Threat Response Team 4.A.3 Verify NO work on Protected Equipment during outage.5. Not applicable to pole 5.A. 1 Not applicable to pole replacement work replacement work 6. Single Points of Vulnerability for 6.A. 1 Verified spare motors and appropriate tooling is Intake Hoist and Draft Tube Hoist on site and available.

6.A. 2 Implement pre-approved lift plan and pre-planned activities to replace hoists motors.6.A.3 Ensure any scheduled hoist inspections and!or maintenance are completed.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 14 RISKS/CONTINGENCY ACTIONS: 1. The risk exists of the duration of this evolution being extended to the point of challenging or exceeding the Technical Specification Action Limit of 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> unavailability.

Certain contingencies shall be in place for this evolution to minimize the possibility of extended unavailability.(Risk 1.A.) Contingencies for managing Critical Path activities include: The Outage Control Center at Keowee shall be fully staffed maintaining 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> continuous coverage and the CAP Manager, Outage Manager, and Technical Support positions also providing 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> continuous coverage.

Hands on verification of parts availability and procedure readiness and correctness shall be performed prior to beginning this evolution.

All assigned Maintenance Teams shall complete scheduled readiness review tasks and ensure all action items are resolved prior to beginning this evolution.

KHS Operations has recently received Just In Time training for OP/O/A/2000/061 "KHS Back-up Auxiliary Power Source" including a detailed walkthrough of the procedure and the normal sequence of events during a dual unit outage. Regulatory Compliance notified of potential exist for NOED.(Risk 1. B.) Station management will pre-select individuals who will comprise a Unit Threat Team in the event a Unit Threat condition is experienced.(Risk 1. C.) Contingencies for minimizing delays during restoration include the identification of Restoration Coordinators by both ONS and KHS Operations.

The Restoration Coordinators shall provide 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage and have performed a prior briefing of restoration procedures and activities with the KHS Operations shifts.ONS shall have dedicated SROs assigned to restoration activities.

KHS shall have one additional NEO from ONS OPS assigned per shift to assist in restorations, peer checks, etc.2. The risk exists of a loss of backup power to ONS from Lee Steam Station.(Risk 2.A.) While KHS is out of service and unavailable, a LCT will be aligned to provide emergency power to energize both ONS Standby Busses via CT-5. LCT Operations shall ensure the additional LCT is available for startup for the duration of this evolution.

The Central Switchyard will have work activities restricted and LCTs will have work activities and access restricted to only routine inspections.

LCT operators will provide 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> continuous coverage.

The ONS OSM shall evaluate establishing a Unit Threat Team and ONS Operations shall initiate a pre-determined plan for the staggered shutdown of the three ONS units. Regulatory Compliance notified that the potential exist for NOED.(Risk 2. B.) To mitigate the risk of complete loss of offsite power contingencies will include: ONS Operations will protect the 230 Switchyard and the TCC has been formally instructed to restrict work and access in surrounding power paths and substations for the duration of this evolution.

KHS Operations shall perform a review of OP/O/A/2000/061 "KHS Back-up Auxiliary Power Source" for initiation as required.

ONS Operations shifts shall review the Blackout Tab of EP/1, 2,3/A/1800/001 prior to beginning this evolution to ensure emergency power License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 15 preparedness.

No orange grid conditions exist prior to beginning outage and none are planned.3. Outside influences such as severe weather and grid unreliability could also adversely affect this evolution.(Risk 3.A.) KHS Operations and OCC Outage Manager shall review weather forecast prior to beginning this evolution.

This evolution will not begin if any weather conditions are predicted that could adversely affect off site power distribution including but not limited to high winds. The OCC Outage Manager shall monitor weather forecasts during each shift and an update will be provided for consideration at the OCC shift meetings.

The OCC Outage Manager and OSM will perform an assessment of changing weather conditions using criteria listed in Conditional Measures.4. Emergent issues could arise with Protected Equipment at ONS.(Risk 4.A.) The OCC Outage Manager and OSM will assess the issue and determine success path in returning the protected equipment.

The OSM shall evaluate establishing a Unit Threat team.5. Not applicable to pole replacement work 6. Single Points of Vulnerability exist with the Intake Hoist and Draft Tube Hoist.(Risk 6.) Maintenance Team 223 Supervisor has verified that spare motors and appropriate tooling is on-site and available.

A lift plan and all necessary planning tasks shall be in place to replace the motor as necessary.

A call-out list has been established listing all craft contacts and NSC contacts required to support replacement of either or both hoists motors.Based on the above information, plant safety and defense in-depth is adequately addressed to perform this maintenance work with all three Oconee units at power.EEEB RAI 8 The Atomic Energy Commission (AEC) General Design Criterion (GDC) 38 described in the Oconee updated final safety analysis report, Section 3.1 states that: Criterion 38 -Reliability and Testability of Engineered Safety Features (Category A): All engineered safety features shall be designed to provide high functional reliability and ready testability.

In determining the suitability of a facility for a proposed site, the degree of reliance upon and acceptance of the inherent and engineered safety afforded by the systems, including engineered safety features, will be influenced by the known and the demonstrated performance capability and reliability of the systems, and by the extent to which the operability of such systems can be tested and inspected where appropriate during the life of the plant.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 16 Since the Oconee design basis requires high functional reliability and ready testability, the staff requests licensee to provide technical and regulatory bases to show that the existing emergency power system design meets AEC GDC 38, considering the TS Completion Time extension requests for KHUs in the last 15 years.Duke Energy Response The reliability of the Keowee Hydro Unit(s) is very high. Below is a calculation of the reliability of the Keowee Units based on number of starts versus the number of failures.KEOWEE RELIABILITY (3YRS)The calculation of the Keowee Units' Reliability is depicted below: Baseline Data (07/01/09

-06/30/12)Total KHU Start/Load Run Demands for KHU-1 749 Total KHU Start/Load Run Demands for KHU-2 632 KHU-1 Failures (07/01/09

-Present)08/31/10 -Keowee Unit 1 electrical generator "X" phase failed the 24KV HiPot test. (FLR#244903)KHU-2 Failures (07/01/09

-Present)09/09/11 -Keowee -ACB #2 experienced a broken auxiliary switch operating rod. (FLR#250820)RELIABILITY CALCULATION:

Reliability

= 1 -(Total Failures / Total Start Load Run) Demands)Total Start/Load Run Demands Total Failures Reliability KHU-1 749 1 0.999 (99.9%)KHU-2 632 1 0.998 (99.8%)As seen in the calculation above, the Keowee Units are highly reliable.

The Units are started regularly (averaging 12-20 starts a month) for commercial generation, maintenance runs, and surveillances.

Technical Specification Surveillance Requirements (TS SR) require the following:

SR 3.8.1.3 -Verify the KHU associated with the underground emergency power path starts automatically and energizes the underground emergency power path. Manually close the SK breaker to each de-energized standby bus.SR 3.8.1.4 Verify the KHU associated with the overhead emergency power path starts automatically and automatically or manually synchronize it to the Yellow bus in 230 kV switchyard.

Energize the underground emergency power path after removing the KHU from the overhead emergency power path.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 17 SR 3.8.1.9 Verify on an actual or simulated emergency actuation signal each KHU auto starts and: a. Achieves frequency

_ 57 Hz and 63 Hz and voltage _> 13.5 kV and < 14.49 kV in < 23 seconds; and b. Supplies the equivalent of one Unit's Loss of Coolant Accident (LOCA) loads plus two Unit's Loss of Offsite Power (LOOP) loads when synchronized to system grid and loaded at maximum practical rate.These testing and surveillance requirements ensure the reliability and testability of the Keowee Units.In the past 15 years, there have only been three LARs submitted requesting extensions to KHU Completion Times; one LAR associated with refurbishment upgrades and two others due to equipment failures.1. LAR 2002-005 -2004/2005 KHU Refurbishment Outages.Requested extension of the Completion Time for restoring one Keowee Hydro Unit (KHU) when both are inoperable from 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> to 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br /> for KHU Refurbishment Upgrades performed prior to April 30, 2005. The proposed LAR also temporarily extends the Completion Time for restoring the KHU associated with the overhead emergency power path from 45 days to 62 days for the same reason.2. LAR 2005-07 KHU2 Emergency TS change due to KHU2 Lockout during testing Requested an additional 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> on top of the 72 Completion Time due to a bus differential relay failure.3. LAR 2006-16 KHU2 TS change due to KHU2 Lockout during testing Requested an additional 30 days on top of the 45 day Completion Time due to a generator rotor pole jumper failure (most of the normal 45 day Completion Time having already been used for the KHU2 Refurbishment Outage in 2005 -item #1 above).Based on the KHU reliability information, TS Surveillance Requirements, and minimal TS Completion time extensions required shown above, the emergency power system design for Oconee meets AEC GDC 38.

License Amendment Request No. 2012-01, Supplement 2 Enclosure

-Duke Energy Response to NRC Request for Additional Information May 28, 2013 Page 18 ATTACHMENT REGULATORY COMMITMENTS The following commitment table identifies those actions committed to by Duke Energy Carolinas, LLC (Duke Energy) in this submittal.

Other actions discussed in the submittal represent intended or planned actions by Duke Energy. They are described to the Nuclear Regulatory Commission (NRC) for the NRC's information and are not regulatory commitments.

Commitment Completion Date 1 Duke Energy will take the necessary steps to ensure the PSW During each KHU tie-in work and the generator pole rewind work will not impact or generator field pole conflict with each other. Note: This does not preclude rewind outage;performing the work concurrently.

expires on 1/1/2015 2 Duke Energy will use a Critical Activity Plan for the Keowee During each KHU generator pole replacement outages for risk mitigation generator field pole purposes.

This plan will include similar risk mitigation strategies rewind outage;to those that are currently used in the Critical Activity Plans for expires on 1/1/2015 scheduled Dual Unit Outages as described in the response to EEEB RAI 7 in the Enclosure to this letter. The Critical Activity Plan will include requirements to notify the Transmission Control Center (TCC) of plant risk changes that increase the plant's sensitivity to offsite power status and to notify the TCC and System Operating Center to take action to ensure grid reliability and minimize risks.