ML071640098
| ML071640098 | |
| Person / Time | |
|---|---|
| Site: | McGuire  |
| Issue date: | 06/08/2007 |
| From: | Gordon Peterson Duke Energy Carolinas, Duke Power Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML071640098 (17) | |
Text
Duke GARY R. PETERSON L Power Vice President McGuire Nuclear Station A Duke Energy Company Duke Power MGO0 VP / 12700 Hagers Ferry Rd.
Huntersville, NC 28078-9340 704 875 5333 704 875 4809 fax grpeters@duke-energy. com June 8, 2007 U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555
Subject:
Duke Power Company LLC d.b.a.
Duke Energy Carolinas, LLC McGuire Nuclear Station, Unit 1 Docket No. 50-369 Emergency License Amendment Request for One-Time Limited Duration Extension of Allowed Outage Time for the Unit 1A Emergency Diesel, Request for Additional Information On June 7, 2007, Duke Power Company LLC d.b.a. Duke Energy Carolinas, LLC (Duke) submitted an emergency license amendment request for a one-time limited duration extension of the Technical Specification Required Action Completion Time associated with the Unit 1 A Emergency Diesel Generator (EDG). The requested extension would allow continued operation of Unit 1 for an additional 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> while repairs and related testing of the 1A EDG are completed.
On June 7, 2007, the NRC Staff electronically requested additional information regarding several issues contained within that request. An additional request for information was received during a teleconference with the NRC Staff June 7 and 8, 2007. The Duke response to the request for additional information is attached.
The responses being provided are clarifications and do not represent any changes to the emergency license amendment request. Also, the conclusions reached in the original determination that the emergency license amendment request contains No Significant Hazards Considerations and the basis for the categorical exclusion from performing an Environmental/Impact Statement have not changed as a result of this request for additional information.
www.dukepower.com rnf
U. S. Nuclear Regulatory Commission June 8, 2007 Page 2 Please direct any questions you may have in this matter to K. L. Ashe at (704) 875-4535.
Sincerely, Gary R. Peterson cc w/
Attachment:
W. D. Travers Administrator, Region II U.S. Nuclear Regulatory Commission Atlanta Federal Center 61 Forsyth Street, Suite 23T85 Atlanta, GA 30303 J. B. Brady NRC Senior Resident Inspector McGuire Nuclear Station J. F. Stang, Jr. (addressee only)
NRC Senior Project Manager U.S. Nuclear Regulatory Commission Mail Stop 0-8 G9A Washington, DC 20555-0001 B. 0. Hall, Senior Chief Division of Radiation Section 1645 Mail Service Center Raleigh, NC 27699-1645
U. S. Nuclear Regulatory Commission June 8, 2007 Page 3 OATH AND AFFIRMATION Gary R. Peterson affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.
GayR Peterson, Site Vice President Subscribed and sworn to me:
Dat, e o-Date I-'
Rc0* U Crarz,Notary Public My commission expires: 0t p 'i C I j~ A 0 1 Date
Response to Request for Additional Information Background Information:
On June 7, 2007, Duke Power Company LLC d.b.a. Duke Energy Carolinas, LLC (Duke) submitted an emergency license amendment request for a one-time limited duration extension of the Technical Specification Required Action Completion Time associated with the Unit 1A Emergency Diesel Generator (EDG). The requested extension would allow continued operation of Unit 1 for an additional 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> while repairs and related testing of the 1A EDG are completed.
On June 7, 2007, the NRC Staff electronically requested additional information regarding several issues contained within that request. An additional request for information was received during a teleconference with the NRC Staff June 7 and 8, 2007.
The responses being provided in this Attachment are clarifications and do not represent any changes to the emergency license amendment request.
RAI Questions and Responses Question 1:
The submittal identified administrative controls to assure plant changes are reflected in the PRA model, but has not stated whether there are outstanding plant changes not yet reflected in the model, and whether those would impact this analysis.
Response
There are 4 plant changes that are not included in the current base PRA model (Rev. 3a). These changes were reviewed and evaluated. One was determined to potentially impact our base model for this application. Therefore we incorporated this change and created an adjusted base case. The issue of interest deals with the timing to manually throttle Auxiliary Feedwater flow when there is a loss of power. The probability of human error was increased in the adjusted base model to reflect this plant change.
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Response to Request for Additional Information Question 2:
The submittal did not address truncation levels per RG 1.177 2.3.3.4.
Response
Truncation issues are not an issue with this risk calculation. The analysis with the diesel in the failed state was performed at the same truncation level as the base case (1 E-9 for CDF and 1 E-1 0 for LERF). A review of the cutsets shows that the diesel failure is in most of the top cutsets. There is adequate representation of the failure in the results that drive the answer so that there was no need to solve to any lower truncation levels. The issue identified in RG 1.177 (most of the failures appearing near the truncation cutoff) does not exist in this analysis.
Question 3:
The submittal needs to identify if credit is taken for the SSF in the risk calculations, and should also address if equipment repair is credited (i.e., for the 1 B diesel).
Response
Credit is taken for the SSF. It is identified in the submittal as a protected system that will not be taken out of service during the extended AOT. No equipment repair for the 1 B diesel (or any other equipment) is credited.
Question 4:
The submittal did not address uncertainty or sensitivity issues per RG 1.177 2.3.5.
Response
Duke agrees with the RG 1.177 statement that risk analyses of AOT extensions is relatively insensitive to uncertainties. We did not credit equipment repair so there are no uncertainties to be evaluated for that issue. We required important systems to remain in service during the AOT so no issues with mean downtimes should exist. We confirmed that common cause was not an issue for the other diesel. Therefore, for the typical issues related to uncertainties, there should be no effect on our analysis. However, we did do two sensitivity studies of key inputs to the analysis. Our base case looked at the 1A diesel out of service and concluded we could support up to an addition 34 day AOT. Sensitivity case #1 doubled the LOOP frequency and concluded that we could support up to an Page 2 of 10
Response to Request for Additional Information additional 20 day AOT. Sensitivity study #2 increased the common cause factor for the 1 B diesel and concluded that we could support up to an additional 19 day AOT.
Question 5:
Provide clarification that the seismic contribution is negligible compared to the non-seismic results.
Response
The frequency of seismic events at certain important levels is compared to the LOOP and tornado frequencies.
The insulators in the switchyard have a mean seismic fragility of approximately 0.3 g, Table 3-1 of the MCGuire IPEEE submittal report. The McGuire design basis earthquake is 0.1 g.
From Figure 3-1 of the McGuire IPEEE submittal, the frequency of exceedance for a 0.1 g (-100 cm/sec 2) event is approximately 3E-04/year. This is much smaller than the nominal LOOP frequency of 5.1 E-02/year. It is also smaller than the tornado initiating event frequency of 7.1 E-04/year.
The frequency of exceedance for a 0.3 g (-300 cm/sec 2) event is approximately 2E-05/year. This is much smaller than both the nominal LOOP frequency of 5.1 E-02/year and the tornado initiating event frequency of 7.1 E-04/year. This is a much better representation of the frequency of a seismic induced LOOP than is the comparison to the DBE.
Question 6:
Additional information is requested regarding the McGuire 1A Emergency Diesel Generator (EDG) jacket water and intercooler pump motor overload alarm of June 6, 2007, motor testing and inspections, and the results of Duke's investigations.
Response
Motor Preventive Maintenance:
Motor periodic maintenance is based upon the Duke Energy Motor Program template prepared by the Duke three site Motor Working Group. The electrical testing for this motor, 1 KDMR0009, is performed on a 3Y frequency. All preventive maintenance tasks are based upon EPRI guideline TR-106857-V8:
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Response to Request for Additional Information Low Voltage Electric Motors (600V and below), as well as benchmarking of other utilities.
The small motor/ intermittent duty template applies and recommends the following periodic maintenance:
External visual inspection: Focus is mainly on visual indication of deterioration.
" Electrical testing including:
o Winding resistance: Integrity of circuit and connections.
o Insulation resistance (Megger): Machine dielectric resistance of ground wall insulation.
o Polarization Index: Indicates moisture or conductive contamination of the winding or lead cables.
" Thermographic data: The main application is to provide an indication of a loose connection.
- Vibration spectra: Very effective in addressing or finding bearing defects, balance, or rotor bar defects.
" DC stepped Hi-pot and Surge testing are typically performed at McGuire on small motors when troubleshooting.
Motor testing and motor inspections are performed under procedure IP/O/A/3190/0005, Rev 21. Per this procedure, the winding resistance must be balanced within 5%. The acceptance criterion for the Megger test is based upon IEEE 43, Recommended Practice for Testing Insulation Resistance of Rotating Machinery. The minimum acceptable reading is 100 Mohms (MO).
Typical Data for the KD motors:
EDG jacket water and intercooler pump motors. Manufactured by Louis Allis, type Pacemaker CJ5B, 20 HP, 550 V, 3 phase, 1800 RPM, Type F insulation, frame size 256T.
Motor 1 A: 1 KDMR0009, Motor 1 B: 1 KDMR001 0, Motor 2A: 2KDMR0009, Motor 2B: 2KDMR0010 Lubrication:
Motors are greased semi-annually on preventive maintenance model work order 510294 using procedure MP/0/A/7300/010. Each motor bearing grease port receives 2 strokes of grease, total per bearing is 4 grams, a volume of 4 cc's.
Unit 1 KD motor lubrication: Both Unit 1 motors were lubricated on 05/30/2007 on work order 01724486.
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Response to Request for Additional Information Unit 2 KD motor lubrication: Both Unit 2 motors were lubricated on 02/06/2007 on work order 01708008.
Pump to motor alignment: The two pumps attached to each KD motor are aligned on a 36 month interval. The 1A KD motor/pump assembly that overheated was aligned within procedural tolerances each time.
09/03/2002 on work order 510514 10/02/2005 on work order 562554 Vibration:
All KD motors have quarterly vibration data taken on 5 positions: H1, V1, H2, V2, A2 from 0-2000 Hertz (H=Horizontal, V=Vertical, A=Axial direction). No degrading trends were identified. All values were at least 50% below the first alert value used for fault identification. The present overall values are low.
Motor 1A: Last monitored 05/08/2007 at 11:55: Maximum spectral peak amplitude 0.059"/sec, Motor 1B: Last monitored 03/28/2007 at 08:13: Maximum spectral peak amplitude 0.095"/sec, Motor 2A: Last monitored 04/03/2007 at 13:24: Maximum spectral peak amplitude 0.073"/sec, Motor 2B: Last monitored 03/20/2007 at 14:05: Maximum spectral peak amplitude 0.034"/sec Electrical. Tests:
Preventive maintenance electrical testing is performed on a 3 year interval, consisting of winding resistance, insulation resistance, and Polarization Index, using a calibrated Baker test instrument Advanced Winding Analyzer Series II. If a problem is indicated, more testing is performed for diagnosis with Engineering concurrence. The phase to phase winding resistance is calculated within the Baker software, not shown below. The Baker maximum resistance is 20,000 MQ and is considered infinity.
Review of the 1A KD motor electrical test data of 4/2/07, 9/2/03, and 11/28/00 shows stable data and no degrading trend. Testing was performed following the motor breaker trip on 6/6/2007. Results:
06/06/07: Phase A-B: 0.718; Phase B-C: 0.721; Phase A-C: 0.715 0; Megged 5,200 MO corrected to 4,851 MO; PI = 1 at >5,000 MO. Testing stopped before Page 5 of 10
Response to Request for Additional Information 1500 volts DC of the hi-pot performed by the Baker test set. The motor was disconnected at the motor lead box with similar diagnostic test results.
Motor 1 A: Last performed on work order 00590722 on 4/2/2007.
04/02/07: Phase A-B: 0.656; Phase B-C: 0.658; Phase A-C: 0.655 0; Megged 20,000 MO corrected to 6,155 MO; PI = 1 at > 5,000 MO.
09/02/03: Phase A-B: 0.683; Phase B-C: 0.675; Phase A-C: 0.655 C; Megged 20,000 MO corrected to 11,486 MO; PI = 1 at 20,000 MO.
11/28/00: Phase A-B: 0.624; Phase B-C: 0.621; Phase A-C: 0.629 0; Megged 20,000 MQ corrected to 9,330 MQ; PI = 1 at 20,000 MO.
Motor 1 B: Last performed on work order 00587434 on 7/18/2006.
Phase to phase balanced within spec; Megged 5,000 MO and corrected to 4,061 M.0; PI = 1 at > 5,000 MO.
Motor 2A: Last performed on work order 00551344 on 8/24/2004.
Phase to phase balanced within spec; Megged 5,100 MO and corrected to 3,865 MO; PI = 1 at > 5,000 MO.
Motor 2B: Last performed on work order 01698439 on 1/23/2007 Phase to phase balanced within spec; Megged 5,100 MO and corrected to 2,219 MO; PI =1 at > 5,000 MC.
Pump data:
Review of the 8 driven pumps (2 per motor) identified two different pump designs:
Pumps 1 A and 2A are Goulds pumps, 3410 3X4-1 OS and 3410 4X6-1 1 H.
Pumps 1B and 2B are Peerless pumps, 30S08-B and 50S09.
Each skid consists of a single motor driving two pumps, one on each end of the motor. For the Goulds pumps, the intercooler water pump is rated at 320 gpm and the jacket water pump rated at 730 gpm. For the Peerless pumps, the intercooler water pump rated at 300 gpm and the jacket water pump rated at 700 gpm.
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Response to Request for Additional Information The A Train pumps on both Unit 1 and 2 were changed via the modification process to Goulds pumps in 1997. Unit 2 pumps were replaced under Work Order number 416420. Unit 1 pumps were replaced under work order number 365977.
Motor data:
All four motors in service on 6/5/07 are manufactured by Louis Allis. They are a Pacemaker Type CJ5B, rated at 20 HP at 1800 synchronous speed on a 256T frame, having a KVA code G. The following summarizes the differences in the motor characteristics, and thus different build dates:
Motor 1A:
Model Number: 9145852002E Speed at rated load: 1745 Full Load Amps: 19.5 Motor 1 B:
Model Number: 9145852001 E Speed at rated load: 1745 Full Load Amps: 19.5 Motor 2A:
Model Number: 4J06335002 Speed at rated load: 1750 Full Load Amps: 21 Motor 2B:
Model Number: 3406320001 Speed at rated load: 1755 Full Load Amps: 21 To summarize motor build age, the difference in model numbers between the 1A and 1 B motors indicates that the motors were built at approximately the same time, and are expected to be the original motors installed for the McGuire diesel dedication in 1975. The 2A and 2B motors have very different model numbers, rated load speed and full load current, as compared to the original 1975 vintage motors. The 2A and 2B motors were replaced as supported by historical work.
order documentation. Motor 2B was replaced on an emergent basis in 1983, work order number 0094017. Motor 2A was replaced in conjunction with a pump modification in 1997, work order number 416420.
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Response to Request for Additional Information Because the Unit 2 motors are more recently installed, they have fewer cycles and less operational wear.
McGuire relies on periodic maintenance and predictive maintenance to prevent failures of these components. The vibration data for all of these motor and pump skids indicates that there are no adverse trend in condition monitoring, and this is also supported by the non-intrusive motor testing that is performed.
Diesel generator and approximate KD motor run time data since 10/2003:
Motor Monthly Average (hrs)
Total (hrs) 1A 9.10 282 1 B 9.82 304 2A 9.04 280 2B 8.96 277 1 A Motor Analysis:
At 18:20:03, approximately 23 minutes after the 1 A Diesel Generator was shutdown, the McGuire Control Room received a non-tripping computer alarm indicating an administrative current overload condition on the 1A KD Jacket Water Cooling Pump Motor, simultaneous with the motor stopping. There were no problems noted during the run. Maintenance was asked to troubleshoot the motor and performed several electrical tests including a Megger, winding resistance, and Polarization Index test. The tests indicated no problem with the motor. Maintenance then performed a stepped DC voltage Hi-Pot and Surge test of the motor. Both tests gave repeatable data and indicated a potential problem with the windings. The motor was removed and sent to an offsite vendor for inspection and attempted repair.
The vendor disassembled the motor and provided photographs of an apparent hard rub between the stator and rotor (Figure 1, 2, and 3). There were also numerous pieces of metal particles inside the end-bell and in the end turn windings of the stator (Figure 2, 3, and 4). Since an apparent rub was in several places around the circumference of the stator winding, the initial cause investigation (based on vendor supplied photos only) suggested a bearing failure.
However, this was later refuted as discussed below.
A rub would explain why the overload alarm was received. Since the computer overload alarm device is sized one standard size smaller than the expected full load current, any drag or rub would cause additional current. This additional current would cause the overload alarm to be picked up as it did. If the motor had continued to run with a degrading rub, then the three phase overload, set at 150% of full load current, would have tripped the motor.
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Response to Request for Additional Information Since the motor was not run after the initial indication of an overload condition, there are insufficient data (vibration, bearing temperatures, running amps, alignment verification) available to determine the actual cause. However, on motor disassembly and preliminary visual inspection of the bearings on 6/7/07 by the experienced Duke motor representative at the motor shop, there were no immediately apparent bearing problems such as cage failures or looseness.
Records indicate that the motor had been lubricated on 5/30/07 and previous quarterly vibration readings associated with diesel testing, performed on 5/08/2007, were also reviewed and found to be within tolerance. No increasing trend of the overall vibration data was identified over the previous 7 years.
Again, based on pictures provided by Shultz Electric earlier on 6/7/07 of the disassembled motor, there appeared to be an indication of a hard rub between the rotor and the stator. However, the apparent rub was actually aluminum that flowed out of the rotor due to heat, that smeared onto the stator. Given that the bearings did not indicate degraded condition, this supports the conclusion that the rotor did not come into contact with the stator.
The pictures, specifically of the bracket, show loose aluminum particles. Any aluminum imbedded in the windings or the slot can provide a tracking path to ground, resulting in degraded indications from the DC HI-POT test and surge test performed at McGuire prior to shipping the motor to the repair facility. The degraded core due to the melted aluminum would lead to higher current draw, causing the overload alarm that was received, and would be expected for this condition.
When the remaining in-service motors were run for common cause failure with process fluid temperatures less than would be present with an operating diesel engine, the absence of overload alarms is sufficient indication that a degraded condition of the rotor is not present on those motors.
At this preliminary point of the causal evaluation, the initiating mechanism causing the rub/smear could be any of the following: excessive heat on the rotor from numerous start attempts or starter relay chattering, a locked rotor condition, a slow start with additional heating from the additional current while accelerating, and unusually heavy load applied from the pump(s). Once the motor was overheated, local hot spots of the aluminum bars could melt, drip down into the small, approximately 0.025" air gap, and smearing would rapidly progress throughout the air gap interface. Vibration analysis can find broken rotor bars, but not this particular type of rotor damage. Rapid degradation of this nature are difficult to detect.
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Response to Request for Additional Information Data:
2A Motor issued: 11/17/97, Motor Stock Code 127784, Material Request number 398843 Work Order number 416420, No Purchase Order number available 2B Motor: Replaced 7/29/1983; Work Order number 0094017; Manufacturer Louis Allis Extent of Condition:
Review of all 4 KD motor data prior to the failure was performed on 6/6/2007 for degrading vibration trends or high amplitudes, and changing electrical test results. No issues were identified. The remaining three KD motors were run to verify operability on 6/6/2007. 1B was started at 11:47 for 5 minutes, 2A at 12:00 for 3 minutes, 2B at 12:05 for 3 minutes. Therefore, based on the available testing, and successful previous quarterly diesel testing, the remaining 3 KD motors are fully operable.
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