NL-12-1567, Response to Request for Additional Information on Emergency Technical Specification Revision Request for 3.8.1 AC Sources - Operating

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Response to Request for Additional Information on Emergency Technical Specification Revision Request for 3.8.1 AC Sources - Operating
ML12207A118
Person / Time
Site: Farley Southern Nuclear icon.png
Issue date: 07/25/2012
From: Ajluni M
Southern Nuclear Operating Co
To:
Office of Nuclear Reactor Regulation, Document Control Desk
References
NL-12-1567
Download: ML12207A118 (28)
v • d • e


Text

Mark J. Ajluni. P.E. Southern Nuclear Nuclear Licensing Director Operating Company. Inc.

40 Inverness Center Parkway Post Office Box 1295 Birmingham, Alabama 35201 Tel 205.992.7673 Fax 205.992.7885 July 25,2012 SOUTHERN . \

COMPANY Docket Nos.: 50-348 NL-12-1567 U. S. Nuclear Regulatory Commission ATIN: Document Control Desk Washington, D. C. 20555-0001 Joseph M. Farley Nuclear Plant Unit 1 Emergency Technical Specification Revision Request for 3.8.1 AC Sources - Operating Ladies and Gentlemen:

8y letter dated July 23,2012, Southern Nuclear Operating Company (SNC) requested an emergency amendment to the Farley Nuclear Plant (FNP) Unit 1 Technical Specifications (TS), Appendix A to Operating License No. NPF-2. In that letter, SNC proposed a one-time change to TS 3.8.1, "AC Sources Operating" Required Action 8.4 Completion Time, to add a note allowing an extended Completion Time of "15 days AND 18 days from discovery of failure to meet LCO," to support repair and restoration of the 18 DG.

Subsequent discussion with the Nuclear Regulatory Commission (NRC), on July 24, 2012, resulted in NRC requests for additional information. The previously requested one-time Completion Time extension is being reduced, from "15 days AND 18 days" to "14 days AND 17 days." This allowance will expire at 21:52 on July 30,2012. This request is to amend the SNC July 23, 2012 submittal. of this letter provides a response to the requests for additional information. To reflect the reduced Completion Time extension, Enclosure 2 is a new marked-up proposed TS page and Enclosure 3 is a new clean-typed proposed TS page. Enclosure 2 and Enclosure 3 of this letter supersede and Enclosure 3 of the July 23,2012 SNC letter. Enclosure 4 is the

'18 DG Repair Schedule.

The conclusions of the Regulatory Evaluation (section 4) and the Environmental Evaluation (section 5) of the July 23, 2012 SNC letter are not changed and remain valid.

This request is being made because damage to the 18 Diesel Generator (DG) occurred during a maintenance run. The proposed change is required to complete the replacement of the damaged components and return the 18 DG to operable status without requiring a plant shutdown.

U.S. Nuclear Regulatory Commission NL-12-1567 Page 2 SNC requests approval of the proposed License Amendment prior to 21 :52 on July 26, 2012 to avoid a unit shutdown. The amendment will be implemented immediately. SNC has determined that the conclusions of the previous 10 CFR 50.92(c) remains unchanged.

This letter contains no Nuclear Regulatory Commission commitments. Should you have any questions concerning this submittal, please contact Doug McKinney at (205) 992-5982.

Mr. M. J. Ajluni states he is the Nuclear licenSing Director of Southern Nuclear Operating Company, is authorized to execute this oath on behalf of Southern Nuclear Operating Company, and to the best of his knowledge and belief, the facts set forth in this letter are true.

Respectfully submitted, IU~~

M. J. Ajluni Nuclear Licensing Director eel before me this 15 JJ> day of ~ } 2012.

~~~~:-O~

My commission expires: I ( z 0 I3 MJNJLSllac

Enclosures:

1. Response to Requests for Additional Information
2. Proposed Changes to the Current TS on Marked-up Page
3. Proposed TS Changes on Clean-typed Page
4. 18 DG Repair Schedule

U.S. Nuclear Regulatory Commission NL-12-1567 Page 3 cc: Southern Nuclear Operating Company Mr. S. E. Kuczynski, Chairman, President & CEO Mr. D. G. Bost, Executive Vice President & Chief Nuclear Officer Mr. 1. A Lynch, Vice President - Farley Mr. B. L Ivey, Vice President - Regulatory Affairs Mr. B. J. Adams, Vice President - Fleet Operations RTYPE: CFA04.054 U. S. Nuclear Regulatory Commission Mr. V. M. McCree, Regional Administrator Mr. R E. Martin, NRR Project Manager - Farley Mr. E. L Crowe, Senior Resident Inspector - Farley Alabama Department of Public Health Dr. D. E. Williamson, State Health Officer

Joseph M. Farley Nuclear Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.8.1 AC Sources - Operating Enclosure 1 Response to Requests for Additional Information (RAls)

Response to Requests for Additional Information (RAls)

Page E1 The statement "Metallic debris believed to be from the piston was found in the lube oil strainer" leads one to conclude that the licensee has not identified the root cause of the event, only "likely causes." Please provide the formal "likely" cause analysis to show what "likely" causes have been positively ruled out and what "likely" causes remain as possibilities. Discuss the entire population of causes considered during the "likely" cause analysis.

SNC Response to RAI 1 The following components/causes have been investigated and eliminated:

Intercooler shaft driven pump, Fuel Rack linkages, Fuel Racks, Fuel Injector Nozzles, Fuel Injector Pumps, Lube Oil, Turbocharger, Grid Disturbance, Jacket Water Cooling, and Fuel Oil.

One thermo assembly installed within the intercooler thermostatic valve failed to actuate during testing following valve disassembly. The valve manufacturer, Robertshaw, and the DG vendor, Fairbanks Morse, have verified that failure of one thermo assembly to actuate will cause a 30% to 35% loss of flow through the valve, which will cause surging through the turbocharger at 100% load on the diesel.

Page E1 In the fourth paragraph the acronym "ACC," is used. Should that be "AAC" or is a new term being introduced and not defined here?

SNC Response to RAI 2 "ACC" was a typographical error; the acronym "AAC" (for Alternate AC) was intended.

On Page E1-3 it says the 2C emergency diesel generator (EDG) is allowed up to 300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> per year at 3250 kilowatts (kW). How many of these hours are currently available (I.e., have not been used during the previous 12 months) to run 2C EDG at 3250 kW during the time of the proposed extended AOT?

SNC Response to RAI 3 This limit is only reached for a 2-hour period each time SNC performs the 24-hour load run.

The last 24-hour load run (FNP-0-STP-80.19) was performed on August 20, 2011.

Therefore, 2 of the 300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> have been used in the past 12 months.

E1-1 Response to Requests for Additional Information (RAls)

On Page E1-9 "protected equipmenf' is listed. Is this equipment going to be in-service during the entire time of the proposed extended AOT? For example, are the Unit 1 A train Service Water pump, RHR pump, charging pump, and CCW pump going to be in-service until the 1B EDG is declared operable? If a protected A train component needs to be shifted to a B train component prior to declaration of EDG 1B operable, will "protected status" also be shifted to the B train component?

SNC Response to RAI 4 The equipment listed on page E1-9 as "protected equipmenf' will be OPERABLE during the proposed extended Completion Time. Depending on plant operation, some of this equipment may not be running and in service. For example, the Unit 1 A-train Residual Heat Removal Pump would not be normally running and in service but would be fully OPERABLE and available to respond to a design basis accident. Other "protected equipmenf' such as the Unit 1 A-train Service Water Pumps would be running to support normal plant operation. A-train equipment function will not be shifted to B-train equipment during the 1B extended Completion Time period.

On page E1-10, items 10 says " ... DG 2C to power Bus 1G through Bus 1J." This may be interpreted to mean Buses 1G, 1Hand 1J, and it does not appear that DG 2C can power bus 1H. A similar observation is made for item 11. Please verify the technical accuracy of these statements.

SNC Response to RAI 5 The statements are accurate; use of the word "through" created unintentional ambiguity.

The intended meaning of item 10 was that DG 2C will be aligned to power Bus 1G by means of Bus 1J (Le., DG 2C will power Bus 1J, which in turn will feed Bus 1G). Similarly for item 11, DG 1C will be connected to Bus 1F by means of Bus 1H (Le. DG 1C will power Bus 1H, which in turn will feed Bus 1F). This arrangement is depicted on the Emergency Distribution diagram included in Enclosure 4 of the July 23, 2012 SNC letter.

On page E1-4 it says "Grid reliability is improved with Unit 1 online, reducing the chance DG power will be needed. Shutting down FNP Unit 1 would ... reduce the available margin for grid electrical reserve during the current high demand summer period ..." Does this mean that upon loss of Unit 1, off-site power will be inoperable for Unit 2 because grid voltage would not be adequate to support safety-related equipment operation for Unit 2? Also, please explain the basis for your answer.

E1-2 Response to Requests for Additional Information (RAls)

SNC Response to RAI 6 No, sufficient margin exists on the grid such that loss of FNP Unit 1 electric output will not result in Unit 2 having inadequate voltage. As shown in Enclosure 4 of the July 23, 2012 SNC letter, Unit 2 feeds the 500 kV switchyard and Unit 1 feeds the 230 kV switchyard. The switchyards are connected through auto transformers and each switchyard is connected to multiple power lines. The 230 kV switchyard supplies startup transformers for both Units.

Operation of the Southern electric transmission grid system is guided by real-time N-1 contingency analysis to maintain the grid voltage within the normal expected range, thus minimizing challenges to degraded grid voltage limits. The system is designed to accommodate loss of generating units. Maintaining Unit 1 on line improves the overall available margin to control grid voltages. Removing Unit 1 from service will not impact Unit 2 voltages but it will reduce available margins since additional generation will have to be brought on line to offset the loss of Unit 1.

The LAR does not identify the root cause of the DG 18 failure, only the "most likely cause."

What other potential causes have been investigated and eliminated slJch as improper or contaminated fuel or lube oil?

SNC Response to RAI 7 The following components/causes have been investigated and eliminated:

Intercooler shaft driven pump, Fuel Rack linkages, Fuel Racks, Fuel Injector Nozzles, Fuel Injector Pumps, Lube Oil, Turbocharger, Grid Disturbance, Jacket Water COOling, and Fuel Oi/.

One thermo assembly installed within the intercooler thermostatic valve failed to actuate during testing following valve disassembly. The valve manufacturer, Robertshaw, and the DG vendor, Fairbanks Morse, have verified that failure of one thermo assembly to actuate will cause a 30% to 35% loss of flow through the valve, which will cause surging through the turbocharger at 100% load on the diesel.

The LAR states that Surveillance Requirement (SR) 3.8.1.6 was performed to address common cause. This is incorrect. Required Action 8.3.1 Or 8.3.2 can be performed to satisfy the minimum TS Required Action for the Condition (One DG set inoperable).

Successful performance of SR 3.8.1.6 verifies Operability of the Operable DG (1 A) but does not satisfy TS 3.8.1, Required Action 8.3.1, "Determine Operable DG set is not inoperable due to a common cause failure."

E1-3 Response to Requests for Additional Information (RAls)

SNC Response to RAI 8 SNC agrees. The LAR reference to SR 3.8.1.6 was intended to imply the end condition that was chosen to address 8.3.2.

When will the stated causal analysis be performed and when will the extent of condition be known?

SNC Response to RAI 9 Formal causal analysis will begin immediately upon conclusion of the 18 DG Outage and will be completed within sixty-days. Extent of condition has been reviewed and only the 1 2A, 1B, and 28 DGs have the Robsertshaw thermostatic valves. The history of these valves has been reviewed and there have been no failures since 1999. Preventive maintenance tasks are currently in place to rebuild these valves every six years on all three DGs. These preventive maintenance tasks were established following the failure in 1999.

RAI10 What other DG components were, or could have been, adversely affected by the engine overheating (e.g., carbon build-up in ring grooves of other pistons)? What was the extent of the overheating and how was this determined?

SNC Response to RAI 10 Damage due to overheating was only observed in the #12 cylinder and the exhaust manifold. This was found once the cylinder was disassembled. All 12 pistons and liners have been inspected by either boroscope or by disassembly. The turbocharger fan was also inspected and found to be free spinning and not affected by this event.

RAI11 When was the 1A DG last 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR test successfully performed?

SNC Response to RAI 11 The last 1-2A DG 24-hour SR test was successfully performed starting at 01: 14 on July 08, 2012 and ending at 03:49 on July 09,2012.

E1-4 Response to Requests for Additional Information (RAls)

RAI12 What structures, systems and components (SSC) in the 1A train are currently monitored in accordance with 10 CFR 50.65, a(1)?

SNC Response to RAI 12 Unit 1 steam generator blowdown AOV's (currently in monitoring with all corrective actions completed) until April, 2013.

1C Service Air Compressor (currently in monitoring with all corrective actions completed) until September, 2012.

No other Unit 1 A Train SCC's are in a(1) status.

RAI13 Was there a high temperature condition (alarm) on the DG prior to the high crankcase pressure engine trip? If not, why?

SNC Response to RAI 13 Per operator statements, no alarms were in until immediately after the trip of the diesel. The "Jacket Water Temp Hi" alarm came in following the diesel trip. There is not a High Intercooler Temperature alarm. The available temperature alarms are: Lube Oil Temperature High, Jacket Water Temp High, Generator Winding Temp High, and Generator Bearings Temp High. The Jacket Water Temp Hi alarm was caused by engine seizure and loss of flow.

RAI14 The LAR uses the phrase "heat exchanger bypass valve" and "thermostatic bypass valve."

Are these referencing the same DG component?

SNC Response to RAI 14 Yes, the terms "heat exchanger bypass valve" and "thermostatic bypass valve" refer to the same component. The LAR also uses the combined term "thermostatic heat exchanger bypass valve" in reference to this component. The "heat exchanger bypass valve" terminology refers to the position of the valve in the heat exchanger flow path, while the "thermostatic bypass valve" terminology refers to the valve's control parameter.

E1-5 Response to Requests for Additional Information (RAls)

RAI15 The LAR states that the 2B DG thermostatic bypass valve will not be inspected at this time.

What is the basis for this and when was the 1B DG thermostatic valve last replaced? What is the vendor recommended repair/replace interval?

SNC Response to RAI15 The 2B Diesel Intercooler Heat Exchanger Thermostatic Bypass Valve was rebuilt, per a preventive maintenance task on June 06, 2009. The 1B DG Intercooler Heat Exchanger Thermostatic Bypass Valve was replaced on February 06, 2008. The recommended rebuild frequency is 8-10 years per the vendor. The SNC preventive maintenance task for this item has been in place since 1999 and is on a six-year frequency.

RAI16 The LAR states that a plant shutdown (Farley Unit 1) would reduce electrical grid reserve

[capacity] during current high demand period. Does the system have sufficient reserve to assure offsite power capability under all analyzed design basis accidents (DBA) (I.e. loss of offsite power/loss of coolant accident (LOOP/LOCA>> and how is this determined?

SNC Response to RAI 16 The Southern electric transmission system has established operating protocols that provide for operating voltages to be maintained at Farley Nuclear Plant at sufficient levels that all equipment credited in analyzed design basis accidents has sufficient voltage to perform its safety function. Maintaining these voltages is considered a top priority by the transmission operators who operate the Southern electric transmission system. Calculations that show required in-plant bus voltage have been performed. Once required voltages were established the required grid voltages were determined. (See also response to RAI 6.)

RAI17 The compensatory measures described in the amendment are typical for a plant to implement when removing a train of SSC from service. What compensatory measures, in addition to the normal compensatory measures, are being implemented?

SNC Response to RAI 17 The following items are additional to what is normally protected when 1B D/G is OOS:

  • 2C DG, B Train 4 kV SWitchgear, Diesel Driven Fire Pump (DDFP)
  • Item 2 through item 11 of section 3.4 of the July 23, 2012 SNC letter E1-6 Response to Requests for Additional Information (RAls)

RAI18 The LAR fails to describe what the scope of the DG repairs will be performed in order to restore DG to Operable. Does the requested Completion Time include inspect/investigate cause(s) of failure?

SNC Response to RAI 18 As described in the July 23, 2012 SNC cover letter, the intercooler heat exchanger thermostatic bypass valve will be repaired and in addition, one piston and one cylinder will be replaced. The requested Completion Time extension includes troubleshooting, visual inspections, repair, reassembly, lube oil system flushing, oil replacement, and testing.

Because a new piston and cylinder was installed, the vendor recommends an extended DG run prior to returning the DG to OPERABLE status.

RAI19 What additional resources have been assigned to the minimum shift staffing to address implementation of the compensatory measures (identify if resource is "dedicated")

SNC Response to RAI 19 The fire watches are provided by non-operations personnel therefore sufficient resources are available. Normal crew complement includes four Reactor Operators. SNC will supplement normal shift staffing with a dedicated fifth Operator to assist the control room staff with implementation of the compensatory measures outlined in item 10 and item 11 of section 3.4 of the July 23, 2012 SNC letter.

RAI20 What additional training has been provided to the operators to address a potential SBO, such as:

1. Offsite power restoration during an SBO.
2. Establishing and maintaining RCS natural circulation
3. Local operation of the DG, including reset of trips and lockouts
4. Manual loading of SBO DG with ECCS loads (as described in the amendment)

SNC Response to RAI 20 The Licensed Operator Continuing Training Program includes loss of power events in conjunction with design basis accidents. To supplement Operator training, relevant required reading will be provided to licensed Operators prior to taking the shift. Operators are trained to perform local operation of DGs. In addition to the required reading, briefings will be conducted for each oncoming shift.

E1-7 Response to Requests for Additional Information (RAls)

RAI21 Has the fire probabilistic risk assessment (PRA) for Farley been completed, i.e., have all fire areas been evaluated? If so, has the fire PRA been Peer Reviewed according to Appendix D of RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2, March 2009?

SNC Response to RAI 21 The Farley Fire PRA has been completed and undergone a RG 1.200, Revision 2, Peer Review against the ASME PRA Supporting Requirements (SRs). The review was conducted by the Westinghouse Owners Group in October 2011 under LTR-RAM-II-12-007, "Fire PRA Peer Review Against the Fire PRA Standard Supporting Requirements from section 4 of the ASMEIANS PRA Standard for the Farley Nuclear Plant Fire Probabilistic Risk Assessment" in accordance with NEI 07-12 as endorsed by RG 1.200 Rev 2. The conclusion of the review was that the Farley methodologies being used were appropriate and sufficient to satisfy the ASMEIANS PRA Standard RA-Sa-2009. The review team also noted that the RIE staff appeared to be applying the NUREG/CR-6850 methodologies correctly.

For the Farley Fire PRA, 88% of the SRs were assessed at Capability Category II or higher, including 8% of the SRs being assessed at Capability Category III. The Farley FPRA had an additional 5% of the applicable SRs assessed at the Capability Category I (CC-1) level.

The FPRA was found to not meet 7% of the applicable SRs. A detailed assessment of each of the findings identified by the Peer Review team has been performed and the findings have been dispositioned.

As stated in SNC letter NL-12-1552, dated July 23, 2012, Enclosure 1, section 3.4, the Farley Fire PRA (FPRA) model has been developed to support Plant Farley's transition to NFPA-805 and includes certain future plant modifications (e.g. incipient detection). These modifications are credited in the FPRA model, but the modifications are not yet installed in the plant.

The effort required to "remove" these modifications from the peer-reviewed FPRA model was the primary reason SNC chose not to develop a risk-based Technical Specifications submittal for this one-time proposed change. However, the FPRA model is a quality fire model and the model was exercised to develop risk insights.

RAI22 On page E1-4, Section 3.3, it says there are two milestones, "Commence performance of maintenance runs" and "Complete maintenance runs." Do the maintenance runs consist of more than the 30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> break in run? If so, please specify what else is included in this activity.

E1-8 Response to Requests for Additional Information (RAls)

SNC Response to RAI 22 Yes, the maintenance runs do consist of more than a 30-hour break-in run. The 1B DG repair schedule is provided in Enclosure 4. The DG runs consist of a 5-minute run, a 10 minute run, a 3O-minute run, a 6-hour run with the special fuel additive, a 20-hour run without the fuel additive, a 5-hour DG load run, and a 4-hour post maintenance run. In addition, a contingency of a 14-hour run is provided.

RAI23 The Standard Review Plan (SRP) Branch Technical Position (BTP) 8-8 addresses onsite EDG and offsite power sources allowed outage time (AOT) extensions. Address the following:

a. Section B of SRP BTP 8-8 discusses having a supplemental power sources available as a backup to the inoperable EDG. Provide justification for not addressing a supplemental power source in the LAR as discussed in the BTP.
b. Section B of SRP BTP 8-8 discusses an AOT extension for a maximum of 14 days.

Provide justification for the proposed 15 days and 18 days AOT for the 1B EDG in the application as compared to the maximum AOT of 14 days allowed by BTP.

SNC Response to RAI 23(a)

Branch Technical Position (BTP) 8-8 "Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions" section B states that the NRC staff evaluates the licensee's request for allowed outage time (AOT) extension from a deterministic as well as probabilistic risk assessment (PRA) perspectives. In addition, section B states that the technical specification must contain Required Actions and Completion Times to verify that the supplemental AC source is available before entering the extended AOT. The BTP also lists several actions that would be implemented during the extended AOT.

SNC is using risk insights but is not using a quantified PRA position for the requested one time emergency technical specification change. The supplemental AC source as described in the BTP is the 2C DG since it is not dedicated for use during design basis events. As described in section 3.1 of the July 23, 2012 SNC letter, the 2C DG is dedicated as the Alternate AC power source for station blackouts events and can be manually operated by operator actions in the control room. The 2C DG will supply the B-train loss of site power loads for Unit 1. Therefore, it is a supplemental source of power during the extended Completion Time for the 1B DG.

The 1B DG extended Completion Time is only being requested for a one-time basis and severe weather is not anticipated during the period of applicability. The system load dispatcher will be contacted daily to ensure no significant grid perturbations are expected.

In addition, a list of equipment to be considered protected, including the Unit 1 steam-driven emergency feed water pump, was listed in section 3.4 Compensatory Measures, of the July 23, 2012 SNC letter. The remaining systems, subsystems, trains, and components that Response to Requests for Additional Information (RAls) depend on the remaining power sources will be verified to be OPERABLE and positive measures will be provided to preclude subsequent testing or maintenance activities on these systems, subsystems, trains, and devices as described in section 3.4 Compensatory Measures.

SNC Response to RAI 23(b)

Branch Technical Position (BTP) 8-8 "Onsite Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions" section B discusses an allowed outage time (AOT) extension for a maximum of 14 days. SNC is revising the proposed 15 days and 18 days AOT for the 1B DG to 14 days and 17 days. This proposed revision meets the BTP criterion of 14 days.

RAI24 Section 3.1 of the LAR states the 2C EDG does not have the capacity to load all the required equipment in the event of a loss of offsite power (LOSP) and loss of coolant accident (LOCA). Provide a detailed justification for using 2C EDG as a replacement of 1B EDG.

SNC Response to RAI 24 SNC is not proposing to replace the 1B DG with the 2C DG. The 1-2A DG is the A-train DG that will provide the electrical power in the event of a Unit 1 design basis accident. The 2C DG would be a defense in depth electrical power source during the period of the 1B DG extension. Also see response to RAI 28. The following is a list of B-train LOCA loads that the 2C DG can power:

  • Charging Pump (709 kW)
  • Component Cooling Water Pump (282 kW)
  • Containment Cooling Fans (202 kW)

Total Loads = 3211 kW, which is below the 300 hour0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> load rating of 3250 kW Loading guidance is provided by plant emergency procedures. The Operator selects the appropriate loads for the event.

RAI25 Section 3.4 of the LAR discusses compensatory measures. Describe how the control room will interact with the grid operation during the proposed extended period.

E1-10 Response to Requests for Additional Information (RAls)

SNC Response to RAI 25 Communication between transmission operators and the control room is accomplished through multiple means of communication such as company phone lines, dedicated computer systems (GEMCOM), and regular land lines as necessary. Communication occurs several times per day as VAR loading or grid conditions are discussed. Also see response to RAI 23(a).

RAI26 Discuss the need for a operator dedicated solely to the operation of DG 2C during the period of the extension.

SNC Response to RAI 26 A dedicated fifth Operator will be added during the extended period while 1B DG is inoperable. Also see response to RAI 19.

RAI27 On pages E1-1 and E1-4 the licensee stated the following:

In addition, to address extent of condition, the 1-2A DG has a scheduled outage later in 2012 in which the thermostatic bypass valve will be inspected and replaced. The 2B DG thermostatic bypass valve was replaced in 2009 and will not be inspected at this time.

The results of the causal analysis for 1B DG will be provided Provide the technical basis for not replacing the thermostatic bypass valves now to prevent a similar failure on the other emergency diesel generators (EDGs). Also explain why these valves were not replaced when the potential issue with these valves appeared to be understood several years ago.

SNC Response to RAJ 27 Our immediate focus and concern is restoration of the 1B DG which will restore two trains of emergency backup power and improve Nuclear safety at the plant. Failure of the thermostatic temperature control valve for the 1B DG was the first failure in the last 13 years, there have been only three instances of corrective maintenance related to these valves for the 1-2A DG, 1B DG, and the 2B DG. Two of those instances occurred on the 1 2A DG, with the last one in 1999. The 1B DG is the third event. Overall failure of this valve is infrequent and therefore immediate change out is not warranted. Scheduling the 1-2A valve replacement and inspection for later this year (October) allows for proper scheduling planning to assure a successful outage. The 2B DG is not near the SNC's change-out frequency of six years.

E1-11 Response to Requests for Additional Information (RAls)

RAI28 Explain the actions that need to be taken to align the 2C EDG as a "replacemenf' for EDG 1B. How much time is needed to align and load EDG 2C during LOSP or SBO event?

When EDG 2C is aligned as a replacement for EDG 1B, how long will it take to align it to support a station blackout (SBO) event on the other unit?

SNC Response to RAI 28 To align the 2C DG as described in the question above is about the same amount of effort for each alignment. This is because the controls and features allow for complete operation from the main control room. STP 80.15 requires testing of the 2C DG every 18 months.

This includes starting, loading, and securing the DG. A 1O-minute acceptance limit is provided in the procedure and is easily met. The following are specific steps to connect the 2C DG to the Unit 1 B train 4 kV Switchgear:

  • Verify 2C Diesel Mode Selector switch in Mode 1
  • Place 2C Diesel Unit Selector Switch to Unit 1
  • Press the 2C Diesel start pushbutton
  • Verify the 2C Diesel output breaker to Unit 1 closes (DJ06-1)
  • Breakers DG02 and DG13 should remain closed and the LOSP sequencer will run itself.

RAI29 On page E1-3 the licensee stated the following:

A monitoring program is being developed which will be implemented following engine repair and during DG testing.

Explain the purpose of the monitoring program and describe how it will be used.

SNC Response to RAI 29 The purpose of the monitoring program is to provide monitoring that wilt confirm proper operation of the 1B DG. The nature of the failure resulted in a major teardown and inspection of the diesel. Monitoring helps ensure that it was assembled correctly and allows for trending. In addition proper operation of the electric governor must also be checked.

RAI30 On page E1-4 the licensee stated the following:

A long range weather forecast has been reviewed and no indication of tropical storm exists, only typical afternoon thunderstorms are predicted.

E1-12 Response to Requests for Additional Information (RAls)

Explain what a typical afternoon thunderstorm is and describe the potential impact it may have to the site. Also provide a list of loss of offsite power events that have occurred at the site.

SNC Response to RAI 30 A typical Dothan, Alabama afternoon thunderstorm during the 1B DG extended Completion Time period is forecasted to consist of 91-92 F temperature, six to eight miles per hour wind, 30-40% chance of rain, and no significant impact to the site. A search of the Farley Licensee Event Report database resulted in no instances of a complete loss of all off-site power events affecting both trains.

RAI31 The repair details that the licensee provided on page E1-4 appear to show a need for only 3 additional days to repair EDG 1B and return it to service. Justify the request for an additional 2 days.

SNC Response to RAI 31 At the time of the July 23,2012 SNC submittal, the trouble shooting process of discovery was in progress and not all of the DG cylinder inspections had been completed to determine if additional damage was present. Since the July 23, 2012 submittal, all of the DG cylinders and liners have been inspected and the requested Completion Time extension has been revised to four days for a total of 14 days and 17 days. In section 3.3 of the July 23, 2012 submittal, the date for the LCO exit was July 29 at 05:00. The difference in the LCO exit schedule and the requested time for the Completion Time extension is due the number of planned maintenance runs needed prior to returning the 1B DG to OPERABLE status. The schedule that was used to develop the first submittal has continued to evolve as maintenance personnel have improved their productivity rate but has also been adjusted for new items. A more detailed schedule is provided in Enclosure 4. This schedule incorporates contingencies for certain aspects of the work that have higher potential for rework and discovery of new items. This schedule reflects our best estimate schedule with contingency allowances.

E1-13

Joseph M. Farley Nuclear Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.8.1 AC Sources - Operating Enclosure 2 Proposed Changes to the Current TS on Marked up Pages

AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3.2 Perform SR 3.8.1 .6 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE DG set.

AND BA Restore DG set to 10 days OPERABLE status.

AND 13 days from discovery of failure to meet LCO ...

{]

C. Two required offsite C.1 Declare required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from circuits inoperable. feature(s) inoperable discovery of when its redundant Condition C required feature(s) is concurrent with inoperable. inoperability of redundant required features AND C.2 Restore one required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> offsite circuit to OPERABLE status.

  • For the 1B Diesel Generator only, the Completion Time that the DG can be inoperable as specified by Required Action BA may be extended beyond the "10 days AND 13 days from discovery of failure to meet LCO" up to "14 days AND 17 days from discovery of failure to meet LCO," to support repair and restoration of the 1B DG. Upon completion of the repair and restoration, this footnote is no longer applicable and otherwise will expire at 21 :52 on July 30, 2012.

Farley Units 1 and 2 3.8.1-3 Amendment No. 146 (Unit 1)

Amendment No. 137 (Unit 2)

Joseph M. Farley Nuclear Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.8.1 AC Sources - Operating Enclosure 3 Proposed TS Changes in Final Typed Format

AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3.2 Perform SR 3.8.1.6 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE DG set.

AND B.4 Restore DG set to 10 days OPERABLE status.

AND 13 days from discovery of failure to meet LCO

  • C. Two required offsite C.1 Declare required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from circuits inoperable. feature(s) inoperable discovery of when its redundant Condition C required feature(s) is concurrent with inoperable. inoperabilityof redundant required features AND C.2 Restore one required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> offsite circuit to OPERABLE status.
  • For the 1B Diesel Generator only, the Completion Time that the DG can be inoperable as specified by Required Action 8.4 may be extended beyond the "10 days AND 13 days from discovery of failure to meet LCO" up to "14 days AND 17 days from discovery of failure to meet LCO," to support repair and restoration of the 1B DG. Upon completion of the repair and restoration, this footnote is no longer applicable and otherwise will expire at 21 :52 on July 30, 2012.

Farley Units 1 and 2 3.8.1-3 Amendment No. (Unit 1)

Amendment No. (Unit 2)

Joseph M. Farley Nuclear Plant Unit 1 Emergency Technical Specification Revision Request for TS 3.8.1 AC Sources - Operating Enclosure 4 1B DG Repair Schedule

Activity 10 MXWO PV I ResourCe IDs I F'V Work Description Original 1Total Float 1Start Number Team Duration IB~OOO 1B DG: OUTAGE DURATION HAMMOCK 21O.0hl lB~015K 1B DG: INSTALL LUBE OIL FLUSH EQUIPMENT CYL12-020 PERFORM INJECTOR POP TEST ON #12 CYLINDER INJECTOR PRE AND FINAL TORQUE HEAD NUTS 4.0h 24-Jul-12 21:00 REASSEMBLE AIR START PIPING, PILOT LINE, 4.0h 24-Jul-12 UPPER JW HEADER, ROCKER ARM HOUSING, 21:00 ROCKER ARM LUBE OIL PIPING, JW TO HEAD

,',', ,v,""'.~T ~'''', 'mm'_>>>~,v,v,_,'nNMuUH,'MW,"_H~_""

CYL6-014 PRE AND ANAL TORQUE HEAD NUTS CYL1-015 REASSEMBLE AIR START PIPING, PILOT LINE, UPPER JW HEADER, ROCKER ARM HOUSING, ROCKER ARM LUBE OIL PIPING, JW TO HEAD CYL5-002 REMOVE AIR MANIFOLD AND EXHAUST HEADER TO CYLINDER CAP SCREWS CYL9-019 1B~015D 1B DG: VERIFY ALL LOWER END WORK IS COMPLETE IB~015E 1B DG: PERFORM A SUMP CLOSEOUT INSPECTION IB~015L 1B DG: TAG TO PERFORM FLUSH LINEUP IB~FO-l 1B DG: ACQUIRE BREAK-IN FUEL OIL IB~020 1B DG:ADJUST RJEL RACK STOP TO NORMAL AFTER MAINTENANCE RUN ~", "w."w, __"w"",~",""""~""~~,~,,,,,y,,~,

IB~021 1B DG:TAG DG FOR RJEL RACK ADJUSTMENT 144.5h,24-JuI-12 '24-Jul-12 17:00  : 19:00 Page 1016 TASK filter: ORA -act not complete.

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ctivity 10 MXWO PV I Resource IDs I PV Work Oescriptloo Original! Total Floatl Start Finish Number Team Duralioo CY112-021 SNC420577 MECHI INSPECT EXHAUST MANIFOLD GASKET AND 4.0h 12.0h 24-Jul-12 124-Jul-12 BELLOWS FOR #12 CYLINDER ....*..*..... ..

~

17:00 121:00 CYl1-016 SNC419843 PERFORM CLOSE OUT INSPECTION IN LINER 1.0h AND INSTALL FUEL INJECTOR IBOO022 1B DG:CLEAR TAG OUT AFTER FUEL RACK ADJUSTMENT CYL5-003 INSTALL RIGGING, REMOVE BOLTING, LIFT HEAD SET ON FLOOR & CLEAN SNC419846 11B DG: JACKET COOLANT SYSTEM iTHERMOSTATIC BYPASS VALVE INSPECDON SNC419847 SNC419847 MECHl IB DG: INTERCOOLER WATER HEAT EXCHANGER THERMOSTATIC BYPASS VALVE INSPECTION

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CYL8-015 REASSEMBLE AIR START PIPING, PILOT LINE, UPPER JW HEADER, ROCKER ARM HOUSING, CY112-016 CYL6-015 IBDG015J IB DG: FILL DG WITH OIL USING VENDOR i EQUIPMENT

?,.~"."," .

IBDGFO-5 1B DG: RECEIVE B.P. FUEL ADDmVE - READY FOR USE CYL6-017 INSPECT EXHAUST MANIFOLD GASKET AND BELLOWS FOR #6 CYLINDER CYL8-016 PERFORM CLOSE OUT INSPECDON IN LINER

. AND INSTALL FUEL INJECTOR SET HEAD ON CYLINDER WITH NUTS HAND TIGHT Page 2 of6 E4-2

ActivitylD MXWO PV PV Work DeSClipUon Finish Number Team CYL6-016 SNC419843 PERFORM CLOSE OUT INSPECTION IN LINER AND INSTALL FUEL INJECTOR CYLl-014 PRE AND FINAL TORQUE HEAD NUTS CYL5-014 PRE AND FINAL TORQUE HEAD NUTS CYL5-015 REASSEMBLE AIR START PIPING, PILOT LINE, UPPER JW HEADERr ROCKER ARM HOUSING,

. ~"~"""""-'"~''i ...,.. .,.,

1BDG015A 1B DG: HI VELOCITY LUBE OIL FLUSH - 4 HRS at 100 DEGREES CYLl-015 REASSEMBLE AIR START PIPING, PILOT LINE, i UPPER JW HEADER/ ROCKER ARM HOUSING, !

WM~"",' NNN_V_' ,." ,'",','".,,,",',. ~----~, " ".. ~'t"','.,-~_'=<m -,

CYL5-016 PERFORM CLOSE OUT INSPECTION IN LINER AND INSTALL FUEL INJECTOR 1BDG016 1B DG: PERFORM A MEGGER AND I TROUBLESHOOTING PLAN ON 1B DG 1BDGFO-2 1B DG: ADD B.P. FUEL ADDITIVE TO BREAK-IN FUEL , ..~, ... ..,

CYLl-016 PERFORM CLOSE OUT INSPECTION IN LINER AND INSTALL FUEL INJECTOR 1BDGFO-3 1B DG: RECIRCULATE BREAK-IN FUEL TO MIX ADDmVE lBDG006A 1B DG JACKET WATER- FILL AND HYDRO SYSTEM lBDG015C 1B DG: TAG LUBE OIL AFTER FLUSH FOR FLU~':l. . Eg~,I~,~~~!:.. ~EMOVAL 1BDG015 1B DG: DISCONNECT LUBE OIL FLUSH 4.0h EQUIPMENT Page 3 of6 TASK tilter: DRA -act not complete.

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tivity ID PV I ResOurce IDs I PV Work Description Orlginall Total Float! start Finish Team Duration 1BOO024 OPS 1B DG: INSTALL BASKETS IN OIL STRAINERS 3.0h 1BOOFO-6 , 1B DG: DELIVER FUEL OIL TO 00 BUILDING AND STAGE FOR BREAK-IN RUN 1BOO006 1B DG JACKET WATER- I-DT-12-R43-00593 CLEAR TAG OUT 1BOO-001 IB DG JACKET WATER HYDRO CONTINGENCY (28 HOURS)

"_,"N~N" '

1BOO0151 . 1B DG AND LUBE OIL DT-12-R43-00592 CLEAR TAG OUT AND stu LO IBOO009 1B DG: REMOVE SCAFFOLDING 1BOOO1O 1BOO015F SNC420287 MECH1 IB DG: USING INSTALLED PUMP FLUSH SYSTEM FOR UP TO 24 HOURS AND OIL HEATUP 1BOO012 IB DG: INmAL POST MAINTENANCE RUN IN SETUP - INCLUDE FUEL RACK STOP 1BOO015G IB DG: CHANGE LUBE OIL STRAINERS

~C2t.!!lNGENCY BASED ON DP)

IBOO015M 1B DG: CHANGE LUBE OIL ALTER (CONTINGINCY BASED ON DP)

IBOO015N 1B DG: TAGOUTTO SUPPORT OIL FILTER CHANGE (CONTINGENCY ONLY IF DP IS 005)

IBOO0150 1B DG: TAG IN FOLLOWING OIL FILTER CHANGE IBOO012A Page 4 of6 TASK filter: DRA -act nct complete.

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,ctMtylD MXWO PV , Resource IDs , PV Work Description Finish Number Team IBOO012B OPS 18 DG: S-min run - Tagout for inspection IBOO012C 18 DG: S-min run - Remove Inspection Coversl Perform Inspection & Re-install W""~""'~"" "~""""_,,,,,,~,

18OO012D 18DG: S-min run - Tagin after inspection 18OO012E 18 DG: Perform 10-min run

~v, IBOO012F IB DG: 10-min run - Tagout for inspection 18 DG: 10-min run - Remove Inspection Covers, Perform Inspection & Re-install 18OO012H 18 DG: 10-min run - Tag in after inspection IBOO012I 18 DG: Perform 3D-min run 18OO012J 18 DG: 30-min run - Tagout for inspection 18OO012K 18 DG: 30-min run - Remove Inspection Covers, Perform Inspection & Re-install

,. ,_",",,"-w IBOO012L 18OO012M 18 DG: Perform 6-Hr Run per MP-14.8 Table 2 0.Oh,26-Jul-12 i03:30

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1800-002 , 1B DG BREAK & RUN LEAK REPAIR 4O.0h 1 26-Jul-12 CONTINGENCY HOURS) '03:30 180000B 18 DG: POST MAINTENANCE RUN IN FOR 20 HRs PER MP-14.B 180000BA 18000088 18 DG: POST MAINTENANCE RUN IN TAKE DATA AND SID OF DG Page 5 of6 E4*5

Activity 10 MXWO PV I Resource IDs I PV Walt; Description Original I Total Floatl Start Finish Number Team Duration IBOO011-1 IB DG: DIESEL COOLOOWN BEFORE RTS SURVEILlANCE 1800-003 IB DG POST MAINTENANCE RUN CONTINGENCY (26 HOURS)

~""/@/"W "__,Vh** ,,'-.' , ' " ' '

1800011 OPS 18 DG: PERFORM RTS SURVEILLANCE 1800019 18 DG:AGGREGATE CONTINGENCY TIME 60925 Page6of6 TASK filter: ORA-act not complete.

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