ML12359A039

Additional Information License Amendment Request for Temporary Tech Spec Change to Add a Required Action Completion Time for One Keowee Hydro Unit Inoperable for Generator Field Pole Rewinds License Amendment Request..

ML12359A039
Person / Time
Site:	Oconee
Issue date:	12/14/2012
From:	Gillespie T Duke Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML12359A039 (25)

Text

T. PRESTON GILLESPIE, Jr.

Vice President Energy, Oconee Nuclear Station Duke Energy ON01 VP / 7800 Rochester Hwy.

Seneca, SC 29672 864-873-4478 10 CFR 50.90 864-873-4208 fax T.Gillespie@duke-energy.com December 14, 2012 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 1 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. The enclosure provides the requested information.

Duke Energy previously requested approval of the proposed LAR by March 1, 2013, to allow the planned maintenance activities described above to be performed beginning in April 2013.

This work has been delayed to January 2014. Therefore, approval by September 30, 2013, will be adequate to support the planned maintenance.

Attachments 1 and 2 provide updated TS markup and retyped pages. Attachment 3 provides a list of regulatory commitments being made as a result of this LAR. 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 December 14, 2012.

Sincerely, TT'1LL&SrI T. Preston Gillespie, Jr., Vice President Oconee Nuclear Station www. duke-energy.com

Nuclear Regulatory Commission License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 2

Enclosure:

Response to. NRC Request for Additional Information Attachments:

Attachment 1, Technical Specification and Bases Markup Attachment 2, Technical Specification and Bases Retype Attachment 3, List of Regulatory Commitments

9-Nuclear Regulatory Commission License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 3 cc w/Enclosure/Attachments Mr. Victor McCree, Regional Administrator U. S. Nuclear Regulatory Commission - Regi6n II Marquis One Tower 245 Peachtree Center Ave., NE, Suite 1200 Atlanta, GA 30303-1257 Mr. John Boska, 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 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

'U ENCLOSURE Duke Energy Response to NRC Request for Additional Information (RAI)

Enclosure - Duke Energy Response to NRC RAI License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 1

RAI 1

The LAR Section 2.2 provides a breakdown of 75 days completion time (CT) for each of the Keowee Hydro Unit (KHU) generator field pole rewind work. The CT includes 15 days for contingency for removal of all 56 field poles, asbestos abatement, complete rewind, and reassembly; and includes another 10 days for contingency for balance runs and balance shots, post modification testing, and commissioning runs.

Provide justification for the above 15 plus 10 days for contingencies, and discuss whether any options were considered to reduce these contingency days.

Response to RAI I The current implementation schedule includes conservative times to execute a typical field rewind on this type of hydro generator field. There are some activities which the exact duration of execution will not be known with 100% certainty until actual execution. Removal of these style field poles, which are secured with a single dovetail and two tapered keys, is dependent on the ease with which the keys can be removed. Variables such as the assembly lubrication, thermal cycling and corrosion can greatly affect the effort required to remove the keys. The schedule is built assuming the keys will be removed with a reasonable effort of welding to both the set and drive key and application of 15-17 tons of force. However a single stuck key could result in a net delay of two to three days. As such the 15-day contingency is appropriate given an absolute worst case scenario of 5 of 56 stuck poles/keys. In addition to the execution variables, Duke Energy must consider and plan for an imbalance in the resulting coupled generator. The current schedule includes a total of four balance runs requiring three balance shots. Once the rewind is complete and the unit is reassembled there remains a possibility that the balancing operation will require additional balance shots or the required balance shots will be of a sufficiently large mass which may required additional time. While this possibility is remote it must be considered as both units have not been balanced since initial commissioning in 1970 and 1971.

RAI 2

The licensee stated in the cover letter that they currently plan to perform the pole windings tasks starting in April 2013 and July 2013, for each KHU. In the safety evaluation of previous amendments Nos. 339, 341, and 340 for Oconee Nuclear Station (ONS) Units 1,2, and 3 respectively, issued on August 5, 2004, the months of March, April, May, and June were identified as peak tornado months at the Oconee site.

Provide justification that the months of April, May, and June are acceptable for the proposed extended maintenance for each KHU in light of being peak tornado months.

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 2 Response to RAI 2 The safety evaluation of previous amendments Nos. 339, 341, and 340, approved a change to TS 3.8.1 Required Action C.2.2.5 and H.2 Completion Times that allowed additional time to be applied provided several conditions were met, one being that the additional time could not be used in March, April, May, or June. Duke Energy elected to perform the needed upgrades during periods when the expected frequency of Loss of Offsite Power (LOOP) events as a result of severe weather is less than the annual average to lower the cumulative risk impact to support the extension of the 60-hour Completion Time of Required Action H.2. This allowed the initiating event frequencies to be reduced by factors ranging from 2 to 4 from the base case values. The only significant risk contribution was when both KHUs were inoperable.

For the Keowee pole rewind work, no additional time beyond what is already allowed by the 60-hour Completion Time of TS 3.8.1 Required Action H.2 is required to support the maintenance activity. As such, Duke Energy does not need to restrict performance of the Keowee pole rewind work to periods when the expected frequency of LOOP events as a result of severe weather is less than the annual average.

RAI 3

An ONS LAR previously submitted in 2008 proposed a new protected service water (PSW) system for mitigating a high energy line break event. Provide a discussion of any potential impact/conflict of PSW amendment related work with the schedule of the KHU pole rewind work, which could adversely impact the availability of any safe shutdown systems.

Response to RAI 3 The planned Keowee generator pole rewind work outage windows are January and July of 2014.

There is no impact/conflict between the PSW work and the Keowee generator pole rewind work.

Additionally, the Keowee generator pole rewind work outage would be scheduled to ensure there is no impact/conflict with PSW related work and that there is no adverse impact on the'availability of any safe shutdown systems.

RAI 4

In an RAI response dated July 12, 2004, relating to a previous LAR pertaining to the KHUs dated August 22, 2002, the licensee provided a list of compensatory measures as regulatory commitments. Since the current LAR is similar to the previous LAR dated August 22, 2002, justify why a list of similar compensatory measures is not needed. Provide an explanation if any of those compensatory measures is not proposed for this LAR.

Enclosure - Evaluation of Proposed Change, License Amendment Request No. 2012-01; SU05plement 1 December 14, 2012 Page 3 Response to RAI 4 For the single KHU outage, proposed LAR No. 2012-01 offers similar compensatory measures to the LAR approved by ONS Amendment Nos. 339, 341, and 340. While they are not listed as regulatory commitments they are required as part of the proposed TS change. Refer to Note 1 and Note 3 for TS 3.8.1 Required Action C.2.2.5 proposed Completion Time for the temporary change restated below:

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

1. No discretionary maintenance or testing allowed on SSF, EFW and essential AC Power Systems.

2. Only applicable one time for each KHU due to generator field pole rewind work.

3. Only applicable if the SSF and EFW are administratively verified OPERABLE prior to entering the extended Completion Time.

Not included are compensatory measures that were taken for the extended dual KHU outages:

1) Manning of the Standby Shutdown Facility during the dual KHU outages;

2) Jocassee Hydro Unit available to provide backup power during the dual KHU outages, and

3) SSF Diesel Generator two hour operability test prior to the start of the first dual KHU outage.

Since this LAR is not requesting an extension to TS 3.8.1, Required Action H.2 Completion Time for two KHUs inoperable, these compensatory measures were not necessary.

Also not included is the requirement not to perform the maintenance during the peak tornado months of March, April, May, and June for the reasons explained in the response to RAI 2 above.

Attachment 4 to the July 12, 2004, RAI response provided an extensive list of Regulatory Commitments primarily related to the extended dual KHU outages that were required to seal the wicket gates for turbine runner and concrete repair. Duke Energy Will use its Risk Management Process to manage the risk to ONS associated with the dual KHU outages and the extended single KHU outage necessary to allow the planned work activities to be performed. Required components of a Critical Activity Plan and differences between the 2004 Critical Evolution Plan and 2014 Critical Activity Plan are provided in the response to RAI 5 below.

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 4

RAI 5

Provide a discussion of the differences between the Critical Activity Plan mentioned in the current LAR and the Critical Evolution Plan discussed in the licensee's letters dated April 28, and June 17, 2004, provided during review of the previous LAR dated August 22, 2002. Provide plans for entering the dual KHU outage and for any immediate need to exit the dual KHU outage.

Response to RAI 5 Critical Evolution Plans were renamed Critical Activity Plans (CAPs) in late 2005 and are primarily developed for application to planned work activities. The required components of Critical Activity Plans are:

a. Written plan for accomplishing the activity

b. Completed activity coversheet

c. Contingency plans for problems that have a reasonable chance to occur

d. Clear criteria for aborting the activity (when appropriate)

e. When appropriate, identification of pre-determined critical step stopping points for the purpose of reviewing the work completed and questioning the work getting ready to be performed. The stopping points should be strategically selected to allow recovery prior to plant impact and expected actions to be performed prior to continuing should be specified (e.g., verification of pre-requisites, verification of contingency/compensatory actions, work group re-brief, review of procedure etc.)

f. Activity Manager assignments include ownership of the plan and responsibility for aborting or initiating the contingency plan. An individual with these responsibilities will be on site during the entire activity

g. Need for just in time training evaluated and documented

h. Specified pre job briefing components and requirements for participation

i. Reviewed by a manager in the Operations organization

j. Plan reviewed and approved by a Group Superintendent (or designee)

k. Plan reviewed and approved by the Plant Operations Review Committee (PORC)

Critical Activity Plans are created and approved by management the weeks leading up to the outage, on average one to two months before the outage starts. Therefore, the Critical Activity Plan(s) for the Keowee Rotor Refurbishment outages in 2014 will not be created until a later date closer to the outage window so a direct comparison between the 2004 Critical Evolution Plan and the 2014 Critical Activity Plan is not feasible. However, below is a list of differences that have been identified that will change from the 2004 plan to the plan which will be created for the 2014 outages:

" One major difference is that the 2004 Critical Evolution Plans were for extended Dual Unit Outage windows (76 and 112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> respectively). The Critical Activity Plan for the upcoming KHU Rotor Refurbishment Outages will be for Dual Unit Outages that do not exceed the TS Completion Time of 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br />. However, the risks and contingencies from the 2004 Dual Unit outage(s) as compared to the Critical Activity Plan for the Rotor Refurbishment Outages will be very similar.

• The 2004 Critical Evolution Plans required an additional Lee Combustion Turbine (LCT) to be running and in standby while in the Dual Unit Outages. This was required due to the increased risk of the extended Dual Unit Outages and the reliability of the old LCTs. The

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 5 2014 Critical Activity Plans will ensure the Standby Busses and CT-5 are energized by a LCT and that Lee has the second LCT available for startup for the duration of this evolution.

• Work, such as sealing the wicket gates and contingencies associated with this work, which is contained within the 2004 Critical Evolution Plan, will not be part of the 2014 Critical Activity Plan. This work is not being performed and not required for the 2014 KHU Refurbishment Outages and will not be included in the 2014 Critical Activity Plan. This same difference applies to any additional work that was performed in the 2004 that will not be performed in 2014, as well as any work identified in the future to be performed during the dual unit outage windows that was not performed in 2004.

• The 2004 Critical Evolution Plan lists a contingency allowing a Jocassee Unit to be aligned to and dedicated as a source of backup power for ONS in the event there are problems with Lee. This contingency did not provide a significant risk benefit and will not be included in the Critical Activity Plan for the Rotor Refurbishment Outages.

• _An addition to the 2014 Critical Activity Plan (not present in the 2004 Critical Evolution Plan) will ensure the Outage Command Center (OCC) at ONS is fully staffed for 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 provide 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> continuous coverage.

Conditional Measures will instruct Operations to follow AP/0/A/1 700/006 "Natural Disaster," which initiates the return of the Keowee Units to service if possible (in the event of severe weather). For other issues that may arise during the outage, the OCC in conjunction with the Operations Shift Manager will be used to determine the best course of action at that time.

RAI 6

Provide a discussion of any activities being made to prepare the Lee Combustion Turbines (LCTs) for the 75 days of KHU pole rewind work. When did the last LCT testing take place per TS Section 5.5.19 (LCT Testing Program)? Provide a brief summary of the test results. From the evaluation of the test history, available test results and associated maintenance records for at least last five years, confirm if any failure has resulted in the loss of a LCT. Will the LCTs be tested prior to starting the KHU generator pole rewind work?

Response to RAI 6 The LCT's and Lee/Central Power path are maintained to nuclear standards and have a robust preventive maintenance (PM) program. Gas turbine inspections and electrical generator inspections on both LCT's are scheduled in 2013. Internal Water Wash of the turbines is performed in the Spring and Fall of each year. This ensures the engine efficiency is maintained at its highest level. Annual boroscope inspections are performed on both LCT's to provide early detection of any internal degradation. Boroscope inspections have been performed annually since installation of the LCT's and no internal issues exist. Gas turbine inspections consist of all maintenance items outlined by the original equipment manufacturer (OEM) which are listed in LM6000 Service Letter 6000-05-03, "Preventative Maintenance and Servicing Checks." Electrical generator inspections are per our prescribed maintenance strategy and include normal electrical

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 6 tests and inspections such as winding insulation test, shaft ground inspections, excitation tests and inspections.

TS Section 5.5.19a verifies an LCT can energize both standby buses using 100KV line electrically separated from system grid and offsite loads every 12 months. This testing was last performed on February 24, 2012, with all acceptance criteria met. Additionally, the requirements of this action are met each time a LCT is aligned to ONS which typically occurs a few times each year.

TS Section 5.5.19b verifies an LCT can supply equivalent of one Unit's LOCA loads plus two Unit's LOOP loads when connected to system every 12 months. This testing was last performed on October 18, 2012, with all acceptance criteria met. The LCT's have a monthly PM (non-TS related) to align each unit to the system grid and load to full power which is well in excess of LOCA/LOOP load requirements.

TS Section 5.5.19c verifies an LCT can provide equivalent of one Unit's LOCA loads within one hour through 100KV line electrically separated from system grid and offsite loads every 24 months.

This testing is completed during Oconee Unit 3 refueling outages and was last performed on May 30, 2012, with all acceptance criteria met.

The new LCT's were placed in service January 2007. Since that time the following failures have occurred that resulted in a Maintenance Rule Functional Failure (MRFF) of an individual LCT.

(The redundant LCT and the power path was available during the below MRFFs.)

April 25, 2007 - LCT 8C failed to start due to Generator Room differential pressure (D/P) low.

The cause of this failure was foreign material (red clay) in a 1/4" instrument tubing line that monitors outside atmosphere. It is believed the foreign material was introduced during construction. Inspections revealed that other transmitters connections have screen nuts connections to prevent foreign material from entering. Screen nuts were added on both LCT units. All sensing lines open to atmosphere were inspected and inspections of these open lines were added to the weekly equipment inspection procedure. No additional problems have occurred since implementing these actions.

August 19, 2007 - LCT 7C failed to start due to Gas Purge Vent Valve Position Error. During startup sequence, the control logic cycles the vent valve open and then closed. The valve cycled as required; however, position feedback was not indicated correctly. The failure was caused by an inadequately designed micro-switch that provides the valve position. The valves/micro-switches are made by Whittaker Controls. The manufacturer indicated they were having failures of these micro-switches. A new more robust designed micro-switch was available. This new switch was installed on all Whittaker Controls valves in service and in-stock. A preventative maintenance task was implemented to visually observe the micro-switch performance by stroking the valve. No failures or problems have been experienced since installation of the new design micro-switches.

June 4, 2008 - LCT 8C unavailable due to faulted automatic voltage regulator (AVR). The cause of the problem was a loose connection in the potential transformer (PT) circuit supplying the voltage signal to the AVR. Actions were taken to check all connections between the PT and the AVR on both LCTs to verify proper terminations. Preventative maintenance

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 7 tasks were created to check all terminals in cabinets that are subject to temperature gradients and vibration that could cause terminals to be loose. Steps were added to check terminal connections in procedures that deal directly with electrical connections, specifically transmitters and motors.

December 2, 2010 - LCT 7C tripped due to Gas Metering Driver Fault. The gas control valve failed due to corrosion in the gear-head that led to seizure of the motor. When the motor seized, a mismatch in demand versus position was generated which led to a Gas Metering Driver Fault shutdown. This valve is located inside the engine compartment beneath the engine. The engine compartment is sealed from water intrusion from the outside. Each LCT has a system called Water Wash which is designed to wash the internal of the engine to remove build-up from the engine blades. During this operation, water leaks out of the engine down onto the equipment below. During commissioning of the LCT, it is known that this valve wasn't protected from water leakage and the gear-head is positioned vertically under the engine. Therefore, the water intrusion occurred during commissioning of the LCT. Other than commissioning when Water Wash was performed by GE, all electrical components have been covered with plastic during Water Wash, as required by procedure. The gas control valve on both LCT 7C and 8C has been replaced. Additionally, a preventative maintenance task has been created to replace the valves.

July 28, 2011 - LCT 8C tripped while operating to system grid due to Variable Stator Vane (VSV) position failure alarm. Feedback of VSV position is provided by redundant LVDT's. The LVDT signals feed into Servo Control I/O Module which is the only common component. The LVDT's do not share common cabling or connectors and are located on opposite sides of the gas turbine. The Servo Control I/O Module was replaced.

August 26, 2011 - LCT 8C experienced a hydraulic pump hose failure during cooldown following grid operation. On January 25, 2012, GE issued Product Bulletin PB-LM6000-IND-0272 indicating premature wear in the hydraulic hose due to inadequate length and/or bend radius. The hoses on both LCT 7C and 80 have been replaced with new hoses outlined in the GE Product Bulletin.

June 21, 2012 - LCT 8C tripped during grid operation due to Liquid Fuel Primary Manifold Temperature signal failure. The signal is supplied by a single element thermocouple with no redundant indications. A review of trends for the point was conducted which yielded the following data, 20 minutes prior to the trip three small (5 degree F) spikes occurred and 9 minutes prior to the trip the spikes'increased in size and number until the trip signal was generated. The signal indication went from good to bad several times after the trip, including after the unit stopped rolling. All wiring connections were verified and no loose connections were found. The thermocouple leads connected to the control system circuit card were lifted and the output from the sensor was checked to the control system. The output intermittently went from a good too bad. A replacement thermocouple was installed and output a constant good value. Two single element thermocouples exist on each LCT that provides a single trip signal. GE was contacted to perform a search of operating experience (OE) on Combustion Turbines Aeroderivative units and found no previous documented failures. A weekly comparison check of the two single element thermocouples on each unit is performed to monitor for erratic indication.

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 8 July 15, 2012 - Instrument Air (IA) hose found leaking on LCT 8C while unit was shutdown.

The flexible hose line deteriorated and pulled out of the crimped end of the raised face flange.

The hose was constructed of reinforced rubber, insulated and heat traced along with the rest of the piping that is exposed to the weather. The wall of the hose was discolored, hardened and brittle from being overheated by the heat trace. The drawing identifies the hose material as metal corrugated hose with external single stainless steel braid not reinforced rubber.

Incorrect hose material was installed during construction that was not designed to be used with heat trace. The hose on LCT 8C and LCT 7C was replaced with a steel corrugated hose as called for by the vendor drawing.

RAI 7

Provide a summary of any recent (during the past year) failure/outage and any preventative maintenance performed on the 100 kV line, and the associated Transformer CT-5 at the Oconee plant to ensure they are functioning as designed.

Response to RAI 7

'Recent failures/outages Since the new LCT's were placed in service January 2007, the following failures have occurred that resulted in a Maintenance Rule Functional Failure (MRFF) of the Lee/Central Power (LCP)

System path.

December 22, 2011 - CT-5 lockout occurred rendering the Lee/Central Power path unavailable. A lightning strike at approximately 1801 on December 22, 2011 is believed to have caused the actuation of relay 87TCT5X, which initiated the lockout of the CT-5 transformer. During the failure investigation process, a Tan Delta cable test was performed on the X, Y, and Z phase cables from CT-5 to the blockhouse (location of breakers SL1 and SL2). The test on the X and Z phases were satisfactory. The Y-phase 4160V cables could not be fully tested due to a fault being detected in the cable. The seven parallel cables that make up the Y-phase were separated so that each cable could be tested individually. The alpha conductor of the Y-phase was tested and determined to be faulted. The faulted portion of this conductor was replaced and all tested satisfactory.

April 28, 2012 - Circuit Switcher CS11 associated with the Lee/Central Power path was not remotely operable due to fiber optic cable damage. CS-1 1 is required to be opened when aligning a LCT to Oconee which is normally controlled by the Transmission Control Center (TCC). When remote control is loss, manual control is provided locally at the Circuit Switcher.

This was a MRFF because an LCT is required to be aligned on a dedicated path within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The steps for TCC to align CS-1 1 are approximately halfway into the procedure and no prior notification of the alignment is given to the TCC. Although it would have been very close to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, ONS had no basis to state the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> time requirement could be met for manual alignment, since no prior notification was given to the TCC. The procedure has been changed to notify the TCC at the beginning of the procedure and immediately dispatch a

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 9 technician if local operation is required. Both LCT's and the power path were available, only the requirement to be aligned with 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> was challenged.

Preventative Maintenance

1) Thermographic scans of the transformer and control cabinet are performed every 6 months.

Last performed on October 11, 2012.

2) Minor PM on CT-5, completed every 18 months, last performed September 9, 2011, next PM due March 12, 2013.

• This PM includes a fan blade inspection, inspect Isolated Phase Bus gaskets on the Low Voltage flanges, Inspect and check the torque on bolted connections on the LV bushings, inspect and clean as required the radiators and coolers, inspect the control cabinets, check doors and gaskets for weather tightness, check for insect nest, dirt and signs of moisture, check for signs of overheating, check and replace if required indicator lamps, check and repair if required heaters and thermostats, cycle each molded case breaker at least 5 times and inspect desiccant in breathers and replace if required.

3) Major PM on CT-5, performed every 3 years, last performed September 9, 2011

• This PM includes everything in the Minor PM plus inspects, cleans and Doble tests bushings, insulators and lightening arrestors and performs visual inspection of all tubing andfittings.

• During the most recent Major PM, the Doble Test from the low voltage windings to the high voltage windings showed an increase of greater than 10% in watts and the %PF correction from the test run on January 30, 2009. After completing additional testing, Oconee engineers and Doble engineers determined a bushing was the cause of the test results with these increases. The decision was made to replace all three low voltage bushings and the ground bushing.

4) A PM is performed on CT-5 relays every 4 years to inspect, clean and calibrate the relays. It was last performed December 16, 2009.

5) The breaker failure relay PM's at LCT Site (CB-1, -2, -11, -12) were performed in April 2012.

RAI 8

Does LCT Station have commercial generation capability as well, and will it be prohibited during the KHU outage periods? Are the 100 kV Lee switchyard and the 100 kV Central switchyard connected to any other nearby power source(s)? Provide a single line diagram of the 100 kV Lee and Central switchyards.

Response to RAI 8 The LCT Station has commercial generation capability. During the KHU outage periods, commercial generation will only be allowed when preventative maintenance or surveillance testing is being performed for the LCT not energizing the standby bus.

When a LCT is aligned to Oconee, a dedicated power path is established using an isolated 100kV transmission line that is not connected to any other power sources or the system grid. If LCT 7C is aligned to Oconee, the following alignment is established per procedure to obtain the isolated

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 10 power path: 1) CB1 and CS-90 closed 2) CB2, CB11, OCB-13, OCB-35, OCB-41 and CS-1I open

3) OCB-101 always closed. Therefore, all connections to the system grid or any other power generation are isolated.

When LCT's are not aligned to Oconee, the 100kV Lee Switchyard and the 100kV Central Switchyard are typically tied together and the only nearby power source, besides the LCT's is the Lee Steam Station (3 unit coal generating site).

A single line diagram of the 100 kV Lee and Central Switchyards is provided below:

r ...................

System Grid P. SS

. d. . . Oconee Nuclear Station i Central 41 iStandby Switchyard Bus 1

- - . - - i S tandby Fant Black

-- - -Bus2 Lee 100kV Swyd System Grid oac Central White 34 Lee Steam runt1,2.3 0C8 13 Lee Steam Station

RAI 9

When one of the LCTs at Lee Station serves as an alternate emergency power source during a dual KHU unit outage, clarify whether the second LCT will be on standby or running status.

Provide a discussion about the established communication protocol with the Lee Station for reenergizing the standby buses.

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 11 Response to RAI 9 The second LCT will be available, not running, for the duration of the dual KHU outage.

Communication is provided from Oconee Control Room to the Lee Steam Station Control Room.

The Lee Steam Station (LSS) Control Room participates in the Oconee Operations conference call at the beginning of each shift. By procedure, upon completion of the shift rounds at the LCT site, the operator reports status of both LCT to Oconee Operations. The Lee Steam Station control room and the LCT site are staffed with continuous coverage while providing power to Oconee.

Three independent lines of communication exist between LSS and Oconee. These consist of a microwave "ring down" line, local phone carrier line, and radios. If the LCT energizing the standby buses at ONS is lost, alarms will be generated at ONS and LCT Site Control Room. The operating procedure at LCT site contains specific steps to align the second LCT to the Lee/Central Power Path to provide power to transformer CT5 and the SL breakers.

RAI 10

In Section 4 of the LAR, the licensee stated that the justification for the TS CT extension is based on the deterministic evaluation. However, to supplement this evaluation and to gain risk insights concerning proposed plant configuration, the licensee also performed a risk assessment. The risk assessment found that the risk impact with the proposed extended CT of 75 days is insignificant.

The licensee also qualitatively stated that the risk analysis shows a small risk increase using the average nominal maintenance unavailability values for the standby shutdown facility (SSF),

emergency feedwater system (EFW) and alternating current (AC) power system. Provide a discussion how the plant addresses the Tier 2 and Tier 3 acceptance guidelines for TS changes provided in Section 2.4 of Regulatory Guide 1.177, Revision 1. If compensatory measures are considered in place to reduce the risk impact during the 75 days CT, provide a discussion of all such measures and include them in the list of regulatory commitments.

Response to RAI 10 The compensatory measures required to reduce the risk impact during the 75 day CT were discussed in the June 27, 2012, LAR in Section 4.0 of the Enclosure. Note 1 to the temporary 75-day CT for TS 3.8.1 RA C.2.2.5 requires that no discretionary maintenance or testing is allowed on SSF, EFW and essential AC Power Systems. Since these are a condition for using the 75-day CT there is no need to list as regulatory commitment. The PRA review also concluded that no discretionary maintenance or testing on the offsite power system (230 kV Switchyard) will be performed and that the operability of required offsite circuits should be maintained at all times.

These two compensatory measures are included in a list of regulatory commitments (Attachment 3 of this submittal).

Tier 2 - Avoidance of Risk-Significant Configurations Risk significant plant equipment outage configurations were identified using PRA insights gained from review of the cut sets.

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 12 The insights gained from the cut sets review show that LOOP events are the dominant risk contributor. The following SSCs show up in the LOOP cut sets as being risk significant and therefore are recommended to be compensatory measures during the Keowee Hydro refurbishment activities.

Compensatory Measures

• Standby Shutdown Facility (SSF)

• Main Feeder Bus 1

• Main Feeder Bus 2

• 4160 V ac Switchgear 1TC

• 4160 V ac Switchgear 1TD

• 4160 V ac Switchgear 3TC

• 4160 V ac Switchgear 3TD

• 4160 V ac Switchgear 3TE

• Standby Bus 1

• Standby Bus 2

• Transformer CT3

• Transformer CT4

• Transformer CT5

• 230/4 kV Transformer 4T

• 4 kV Switchgear Center B3T

• Turbine Driven Emergency Feedwater Pump

• Emergency Feedwater System Header Tier 3 - Risk-Informed Configuration Risk Management 10 CFR 50.65 (a)(4), RG 1.160, RG 1.182, and NUMARC 93-01 require that prior to performing maintenance activities, risk assessments shall be performed to assess and manage the increase in risk that may result from proposed maintenance activities. These requirements are applicable for all plant modes. NUMARC 91-06 requires utilities to assess and manage the risks that occur during the performance of outages.

The proposed LAR will not result in any significant changes to the current configuration risk management program. The existing program uses a blended approach of quantitative and qualitative evaluation of each configuration assessed. The Oconee on-line computerized risk software (Electronic Risk Assessment Tool or ERAT) considers both internal and external initiating events with the exception of seismic events. Thus, the overall change in plant risk during maintenance activities is expected to be addressed adequately considering the proposed amendment.

Oconee has several Nuclear System Directives (NSD) and Work Process Manual (WPM) procedures in place to ensure that risk significant plant configurations are avoided. These documents are used to address the Maintenance Rule requirements, including the on-line (and

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement. 1 December 14, 2012 Page 13 off-line) Maintenance Policy requirement to control the safety impact of combinations of equipment removed from service. The key documents are as follows:

• NSD 213, "Risk Management Process"

• NSD 403, "Shutdown Risk Assessment (Modes 4, 5, 6, and No-Mode) per 10 CFR 50.65 (a)(4)"

• NSD 415, "Operational Risk Management (Modes 1-3) per 10 CFR 50.65 (a)(4)"

• WPM-609, "Innage Risk Assessment Utilizing Electronic Risk Assessment Tool (ERAT)"

• WPM-608, "Outage Risk Assessment Utilizing Electronic Risk Assessment Tool (ERAT)"

More specifically, the NSDs referenced above address the process, define the program and state individual group responsibilities to ensure compliance with the Maintenance Rule. The Work Process Manual procedures provide a consistent process for utilizing the computerized software assessment tool, ERAT, which manages the risk associated with equipment inoperability.

The Electronic Risk Assessment Tool (ERAT) is a Windows-based computer program used to facilitate risk informed decision making associated with station work activities. Its guidelines are independent of the requirements of the Technical Specifications and Selected Licensee Commitments and are based on probabilistic risk assessment studies and deterministic approaches.

Additionally, prior to the release of work for execution, Operations personnel must consider the effects of severe weather and grid instabilities on plant operations. This qualitative evaluation is inherent of the duties of the Work Control Center Senior Reactor Operator (WCC SRO).

Responses to actual plant risk due to severe weather or grid instabilities are programmatically incorporated into applicable plant emergency or response procedures.

The key safety significant systems impacted by this proposed LAR are currently included in the Maintenance Rule program, and as such, availability and reliability performance criteria have been established to assure that they perform adequately.

Enclosure - Evaluation of Proposed Change License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 Page 14

RAI 11

Provide an expiration date for this one-time TS change. For example, Note 2 could be revised to state "Only applicable one time for each KHU due to generator field pole rewind work, and expires on January 1, 2014."

Response to RAI 11 Duke Energy currently plans to perform this work in 2014. Note 2 has been revised to state "Only applicable one time for each KHU due to generator field pole rewind work and expires on January 1, 2015." The revised TS 3.8.1 retyped page and markup page are provided in and 2 to this enclosure. Should this schedule change such that the work will not be completed in 2014 and prior to issuance of the amendment approving this request, Duke Energy plans to submit a supplement to this change requesting a later expiration date.

License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 ATTACHMENT 1 TECHNICAL SPECIFICATION & BASES MARKUP

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2.2.4 Verify alternate power 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> source capability by performing AND SR 3.8.1.16.

Every 31 days thereafter AND C.2.2.5 Restore KHU and its 28 days when Condition required overhead due to an inoperable emergency power path Keowee main step-up to OPERABLE status. transformer Not applicable during AND generator field pole rewind work or until 1 ------

KrT=-------NT year after KHU An dditio al 3 day ,;

declared OPERABLE al wed rior t following rewind work. ovemr er 3, 006 at 1029 ours AND NOTE------ 45 days from discovery

1. No discretionary of initial inoperability maintenance or testing when Condition due to an allowed on SSF, EFW inoperable KHU if not and essential AC Power used for that KHU in the Systems previous 3 years

2. Only applicable one time for each KHU due to generator field pole (continued) rewind work and expires on January 1,2015.

3. Only applicable if the SSF and EFW are administratively verified OPERABLE prior to entering the extended Completion Time.

75 days from initial inoperability when Condition due to an inoperable KHU to perform generator field pole OCONEE UNITS 1, 2, & 3 ndment Nos. 354, 356, & 55I rewind work

AC Sources - Operating B 3.8.1 BASES ACTIONS C.1, C.2.1, C.2.2.1, C.2.2.2, C.2.2.3, C.2.2.4, and C.2.2.5 (continued) repairs which are estimated to be necessary every six to eight years.

Also, generator thrust and guide bearing replacements are necessary.

Other items which manifest as failures are expected to be rare and may be performed during the permitted maintenance periods. As such, the 45 The temporary 75 day day restoration time of Required Action C.2.2.5 is allowed only once in a restoration time of Required three year period for each KHU. This Completion Time is 45 days from Action C.2.2.5 is allowed for each KHU to perform generator discovery of initial inoperability of the KHU. This effectively limits the time field pole rewind work. The 75 the KHU can be inoperable to 45 days from discovery of initial day Completion Time is inoperability rather than 45 days from entry into Condition C and modified by three notes that precludes any additional time that may be gained as a result of switching provide conditions for using the an inoperable KHU from the underground to the overhead emergency extended outage. Note 1 indicates that no discretionary power path. The Completion Time is modified b a nt indictin an maintenance or testing is additional 30 days is allowed when entering Condition C prior to allowed on Standby Shutdown November 3, 2006. at 1029 hours0.0119 days <br />0.286 hours <br />0.0017 weeks <br />3.915345e-4 months <br />.

Facility (SSF), Emergency Feedwater (EFW), and Required Actions C.2.2.1, C.2.2.2, C.2.2.3, and C.2.2.4 must be met in essential alternating current order to allow the longer restoration times of Required Action C.2.2.5.

(AC) Power Systems. Note 2 indicates that the 75 day Required Action C.2.2.1 requires that both standby buses be energized Completion Time is only using an LCT through the 100 kV transmission circuit. With this applicable one time for each arrangement (100 kV transmission circuit electrically separated from the KHU due to generator field pole system grid and all offsite loads), a high degree of reliability for the rewind work and expires on emergency power system is provided. In this configuration, the LCT is January 1, 2015. Note 3 serving as a second emergency power source, however, since the 100 kV indicates that it is only applicable ifthe SSF and EFW transmission circuit is vulnerable to severe weather a time limit is are administratively verified imposed. The second Completion Time of Required Action C.2.2.1 OPERABLE prior to entering permits the standby buses to be re-energized by an LCT within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> in the extended Completion Time. the event this source is subsequently lost. Required Action C.2.2.2 This'increases the probability requires suspension of KHU generation to the grid except for testing. The even in the unlikely event of an additional failure that the risk restriction reduces the number of possible failures which could cause loss significant systems will function of the underground emergency power path. Required Action C.2.2,3 as required to support their requires verifying by administrative means that the remaining KHU and its safetv function. required underground emergency power path and both required offsite sources are OPERABLE. This provides additional assurance that offsite power will be available. In addition, this assures that the KHU .and its required underground emergency power path are available.

Required Action C.2.2.3 also requires verifying by administrative means that the requirements of the following LCOs are met:

[ The 45 day Completion Time is modified by a Note indicating that it is not applicable ouring generator ielCi pole rewina work or unil -1year arter rIiu aeclared UO(PEALE following rewind work. This note is added to avoid using up the 45 day Completion Time concurrent with the 75 day Completion Time and preserves some time to perform emergent maintenance work should the need arise after a one year waiting period.

OCONEE UNITS 1, 2, & 3 B 3.8.1-10 BASES REVISION DATED.4Q414Q

License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 ATTACHMENT 2 TECHNICAL SPECIFICATION & BASES RETYPE

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2.2.5 Restore KHU and its 28 days when Condition required overhead due to an inoperable emergency power path Keowee main step-up to OPERABLE status. transformer AND NOTE------

Not applicable during generator field pole rewind work or until 1 year after KHU declared OPERABLE following rewind work.

45 days from discovery of initial inoperability when Condition due to an inoperable KHU if not used for that KHU in the previous 3 years AND NOTE------

1. No discretionary maintenance or testing allowed on SSF, EFW and essential AC Power Systems.

2. Only applicable one time for each KHU due to generator field pole rewind work and expires on January 1, 2015.

3. Only applicable if the SSF and EFW are administratively verified OPERABLE prior to entering the extended Completion Time.

75 days from initial inoperability when Condition due to an inoperable KHU to perform generator field pole rewind work (continued)

OCONEE UNITS 1, 2, & 3 3.8.1-5 Amendment Nos.

AC Sources - Operating B 3.8.1 BASES ACTIONS C.1, C.2.1, C.2.2.1, C.2.2.2, C.2.2.3, C.2.2.4, and C.2.2.5 (continued) the KHU can be inoperable to 45 days from discovery of initial inoperability rather than 45 days from entry into Condition C and precludes any additional time that may be gained as a result of switching an inoperable KHU from the underground to the overhead emergency power path. The 45 day Completion Time is modified by a Note indicating that it is not applicable during generator field pole rewind work or until 1 year after KHU declared OPERABLE following rewind work.

This note is added to avoid using up the 45 day Completion Time concurrent with the 75 day Completion Time and preserves some time to perform emergent maintenance work should the need arise after a one year waiting period.

The temporary 75 day restoration time of Required Action C.2.2.5 is allowed for each KHU to perform generator field pole rewind work. The 75 day Completion Time is modified by three, notes that provide conditions for using the extended outage. Note 1 indicates that no discretionary maintenance or testing is allowed on Standby Shutdown Facility (SSF), Emergency Feedwater (EFW), and essential alternating current (AC) Power Systems. Note 2 indicates that the 75 day Completion Time is only applicable one time for each KHU due to generator field pole rewind work and expires on January 1, 2015. Note 3 indicates that it is only applicable if the SSF and EFW are administratively verified OPERABLE prior to entering the extended Completion Time. This increases the probability even in the unlikely event of an additional failure that the risk significant systems will function as required to support their safety function.

Required Actions C.2.2.1, C.2.2.2, C.2.2.3, and C.2.2.4 must be met in order to allow the longer restoration times of Required Action C.2.2.5.

Required Action C.2.2.1 requires that both standby buses be energized using an LCT through the 100 kV transmission circuit. With this arrangement (100 kV transmission circuit electrically separated from the system grid and all offsite loads), a high degree of reliability for the emergency power system is provided. In this configuration, the LCT is serving as a second emergency power source, however, since the 100 kV transmission circuit is vulnerable to severe weather a time limit is imposed. The second Completion Time of Required Action C.2.2.1 permits the standby buses to be re-energized by an LCT within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> in the event this source is subsequently lost. Required Action C.2.2.2 requires suspension of KHU generation to the grid except for testing.

The restriction reduces the number of possible failures which could cause loss of the underground emergency power path. Required Action C.2.2.3 requires verifying by administrative means that the remaining KHU and its required underground emergency power path and both OCONEE UNITS 1"2, & 3 B 3.8.1 -10 BASES REVISION DATED xx/xx/xx

License Amendment Request No. 2012-01, Supplement 1 December 14, 2012 ATTACHMENT 3 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 No discretionary maintenance or testing on the offsite power During 75 day CT system (230 kV Switchyard) will be performed for TS 3.8.1 RA C.2.2.5 2 Operability of required offsite circuits should be maintained at all During 75 day CT times. for TS 3.8.1 RA C.2.2.5