L-11-335, Supplemental Information for License Amendment Request Regarding Offsite Electric Power System Acceptability Until December 12. 2011

Supplemental Information for License Amendment Request Regarding Offsite Electric Power System Acceptability Until December 12. 2011

ML112900202
Person / Time
Site:	Perry
Issue date:	10/16/2011
From:	Bezilla M FirstEnergy Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-11-335, TAC ME7263
Download: ML112900202 (13)

Text

m^^*j*\f\f Perry Nuclear Power Plant

^^^^^^ 10 Center Road FirstEnergy Nuclear Operating Company Perry, Ohio 44081 Mark B. Bezilla 440-280-5382 Vice President Fax: 440-280-8029 October 16, 2011 L-11-335 10 CFR 50.90 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

Perry Nuclear Power Plant Docket No. 50-440, License No. NPF-58 Supplemental Information for License Amendment Request Regarding Offsite Electric Power System Acceptability until December 12. 2011 (TAC No. ME7263)

By letter dated October 11, 2011, FirstEnergy Nuclear Operating Company (FENOC) submitted a license amendment request to revise the Perry Nuclear Power Plant Technical Specifications to temporarily use a delayed access circuit as one of the required offsite circuits between the offsite transmission network and the onsite Class 1E alternating current electric power distribution system. By letter dated October 12, 2011, FENOC responded to a Nuclear Regulatory Commission (NRC) staff information request. On October 13, 2011, the NRC staff requested additional information to support review of the license amendment request. Clarifying discussion between NRC and FENOC staff on the same date identified eleven total questions remaining to be addressed. The responses to these questions are provided in the attachment to this letter.

There are no regulatory commitments contained in this submittal. If there are any questions or if additional information is required, please contact Mr. Phil H. Lashley, Supervisor- Fleet Licensing, at (330) 315-6808.

I declare under penalty of perjury that the foregoing is true and correct. Executed on October f&, 2011.

Sincerely, Mark B. Bezilla

Attachment:

Supplemental Information Requested October 13, 2011 cc: NRC Region III Administrator NRC Resident Inspector Office NRC Project Manager Executive Director, Ohio Emergency Management Agency (NRC Liaison)

Utility Radiological Safety Board

Attachment L-11-335 Supplemental Information Requested October 13, 2011 Page 1 of 12 The following information is provided to supplement a license amendment request (LAR) for the Perry Nuclear Power Plant (PNPP) regarding temporary use of a delayed access circuit in the offsite electric power system until December 12, 2011.

The Nuclear Regulatory Commission (NRC) staff questions are presented in bold type, followed by the FirstEnergy Nuclear Operating Company (FENOC) responses.

1. Regarding Regulatory Commitment List #5, what tests [or] monitoring will be performed on the Unit 2 startup transformer (SUT) to detect potential failure that was not performed on the Unit 1 SUT during the requested period (until December 12, 2011)?

Response: For the Unit 2 startup transformer, the predictive monitoring is electromagnetic interference (EMI)/acoustic monitoring, dissolved gas analysis (DGA) including oil screening and thermography. They will be performed more frequently (FENOC's response to Question 2 addresses frequency). These tasks can be performed with the unit in service to better detect a potential failure of the transformer.

The detection of gases dissolved in transformer oil is often the first available indication of a transformer malfunction. Oil analysis is performed at an off-site laboratory where the dissolved gasses are measured with a gas chromatograph.

Conditions that may be indicated by DGA results include: arcing, corona discharge, low-energy sparking, severe overload, pump motor failure and insulation overheating. DGA also provides information on the condition of the cellulose winding insulation material. Nuclear Electric Insurance Limited (NEIL) required frequency for DGA sampling is at least once every six months and more often if there is an active condition in the transformer causing gassing.

Thermography provides for detection of loose or high resistance connections, strong local eddy current heating, bushing oil level anomalies and proper cooler operation. Thermography is performed at a timed-based interval of every six months and after any maintenance that involves disturbing the high voltage terminations or when increased loading is experienced. Supplementary thermographic inspection may be performed when conditions exist that will allow for enhanced inspection results, such as when the transformer is loaded above the routine levels. NEIL required frequency to receive credit is annual.

EMI testing is a technology that has been used at Perry for a period of time.

Acoustic monitoring can also be used to determine changes in large transformer performance.

Oil screening provides an indication of insulating oil quality. Oil quality can degrade as a result of the effects of aging, contamination, voltage surges, and mechanical looseness that may promote arcing. Observed parameters include:

water content (ppm), percent moisture saturation, acid number, inhibitor concentration, interfacial tension, metal particulate and dielectric strength.

Attachment L-11-335 Page 2 of 12

2. At what frequency will this additional monitoring be performed on the Unit 2 SUT?

Response: For the Unit 2 startup transformer, the frequency of existing predictive monitoring is provided in the table below.

Perry will perform the following predictive monitoring on the Unit 2 startup transformer at the below established frequencies to provide adequate assurance that a fault can be detected. DGA analysis frequencies are established from Institute of Electrical and Electronics Engineers (IEEE) C57.104-2008 based on conditional monitoring. Prior to the Unit 1 startup transformer failure, the DGA frequency was established at quarterly due to moisture levels being in an accelerated condition monitoring category (Category 2 per Table 1 of IEEE). The frequency of DGA analysis has been further accelerated to monthly for conservatism in the period where the Unit 1 startup transformer is out of service.

The existing thermography frequency is semi-annual and existing EMI/acoustic monitoring frequency is annual, both based on Electric Power research Institute (EPRI) guidance. The existing (current) and proposed (new) frequencies are shown below.

Predictive Monitoring Frequency Predictive Current Frequency New Frequency Technology with Unit 1 SUT out-of-service Dissolved Gas Quarterly Monthly Analysis Thermography Semi-Annual Weekly EMI/Acoustic Annual Two Weeks

Attachment L-11-335 Page 3 of 12

3. Please confirm that TS SR 3.8.1.1 was successfully met and documented (at the required SR Frequency), for the periods identified in the table (found on Attachment 2, L-11-333, Page 4 of 5) when crediting the backfeed capability as a TS 3.8.1 qualified offsite circuit in accordance with 10 CFR 50.36(c)(3), Surveillance requirements.

Response: The previous response in L-11-333 provided data for the past five years (since 2006) to demonstrate performance of Technical Specification (TS)

Surveillance Requirement (SR) 3.8.1.1 at the required frequencies. Surveillance Instruction "OFF-SITE POWER AVAILABILITY VERIFICATION" is performed to verify TS SR 3.8.1.1. TS SR 3.8.1.1 was successfully met at the required SR frequency as verified by review of operating logs, surveillance test records, and work order completion data for all of the periods identified. Three additional occurrences were identified when the backfeed was verified available that were missed in the previous response for FENOC Letter L-11-333 due to differences in the word search criteria. Those three occurrences (2/13/07,12/29/09 and 9/27/10) were identified in an engineering trend database, followed up by confirmation through review of operations logs, and verification through surveillance test records and work order completion data that TS SR 3.8.1.1 was successfully met on those dates.

Date Operability Backfeed verified Results 4/10/06 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 6/5/06 Unit 2 Startup declared inoperable Verified backfeed available Acceptable 7/5/06 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 2/13/07 Unit 2 Startup declared inoperable Verified backfeed available Acceptable 9/4/07 Unit 2 Startup declared inoperable Verified backfeed available Acceptable 9/26/07 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 10/13/07 Unit 2 Startup declared inoperable Verified backfeed available Acceptable 6/29/08 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 9/22/08 Unit 2 Startup declared inoperable Verified backfeed available Acceptable 10/22/08 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 10/24/08 Unit 2 Startup declared inoperable Verified backfeed available Acceptable 7/13/09 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 7/27/09 Unit 2 Startup declared inoperable Verified backfeed available Unacceptable*

8/17/09 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 12/29/09 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 5/24/10 Unit 2 Startup declared inoperable Verified backfeed available Acceptable 9/27/10 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 9/26/11 Unit 1 Startup declared inoperable Verified backfeed available Acceptable 9/29/11 Unit 1 Startup failed Verified backfeed available Acceptable

• The surveillance instruction coverpage initially marked unacceptable since S111 could not be electrically operated. The backfeed was verified available. Tools, procedures and access were pre-staged and the backfeed circuit was determined to be operable as a second source of offsite power.

Attachment L-11-335 Page 4 of 12

4. FENOC states on page 5 of 29 of the LAR that the terms "physically independent" and "qualified" are considered to have the same meaning.

Please explain how compliance with LCO 3.8.1 (a) was met during periods when the Unit 2 SUT was declared inoperable as identified in the table on Attachment 2, L-11-333, page 4 of 5 since both the Unit 1 SUT and the auxiliary transformer (backfeed) require bus L10 and the bus LH1A supply breaker to be Operable.

Response: The Unit 1 SUT has the capability to supply busses L10 and L20 through electrically independent circuits. The Unit 1 SUT is fully capable of providing power to bus L20 and its downstream engineered safety feature (ESF) buses, without relying on bus L10, the LH1A transformer, or its supply breaker.

Bus L10 is required to be operable to support a backfeed alignment through the main and auxiliary transformers. Either bus L10 or bus L20 would be available to provide power to the ESF buses through either the Unit 1 interbus transformer LH-1-A or the Unit 2 interbus transformer LH-2-A respectively. Therefore, compliance with Limiting Condition for Operation (LCO) 3.8.1 (a) was met by verification that two independent offsite sources were available, through the Unit 1 startup transformer (immediately available source) and through the main and auxiliary transformer backfeed (delayed source).

Discussion with the NRC staff indicated the concern with bus L10 is related to the connection between the L10 and L20 busses that the NRC staff postulated to be a single point vulnerability if the L10 bus were to fail. With the exception of the auxiliary compartment, the L10 and L20 busses are located in separate buildings.

The auxiliary compartments (L1001 and L2001) house the bus tie breakers between bus L10 and bus L20 and are segregated from their associated busses by metal sheeting, such that a failure of one of the bus compartments is not expected to cause a failure of another compartment or prevent transfer of loads to the alternate bus. The design of the ITE HK switchgear (Reference ITE Bulletin 8.20-1 C) includes grounded metal enclosures that isolate major parts of the primary circuit such as circuit breakers, transformers, and busses. Electrical separation between the L10 and L20 busses is also provided by breakers L1001 and L2004 for the L10 crosstie to L20, and between breakers L2001 and L1004 for the L20 crosstie to L10. In summary, the two busses are effectively isolated both physically and electrically to preserve the independence of the qualified circuits, providing confidence that a catastrophic failure of one would not affect the other.

Attachment L-11-335 Page 5 of 12

5. Please provide data (table preferred) to show the cyclic history of Unit 2 SUT as compared to the cyclic history of Unit 1 SUT and provide a brief assessment, using this and any other pertinent related data, to confirm that the Unit 2 SUT has not been adversely affected by its cyclic history.

Response: See attached table for cyclic history of the Unit 2 SUT and the Unit 1 SUT. Data collection was only readily available for the period of 2000-2011 through the current database structure. Comparing both transformers' cyclic history over that period indicates the Unit 2 SUT has been cycled less often than the Unit 1 SUT.

Start up Transformer Outage Periods Year 2000 to Present Uniti Unit 2 Start End Start End 09/17/2000 09/18/2000 10/02/2000 11/07/2000 10/01/2001 10/10/2001 10/22/2001 10/26/2001 10/31/2001 11/01/2001 12/25/2001 01/05/2002 10/28/2002 10/30/2002 11/04/2002 11/09/2002 04/05/2003 04/09/2003 09/29/2003 10/01/2003 03/22/2004 03/25/2004 05/10/2004 05/26/2004 09/02/2004 09/02/2004 09/06/2004 09/07/2004 10/28/2004 10/30/2004 11/21/2004 11/25/2004 02/22/2005 02/22/2005 09/28/2005 09/29/2005 04/10/2006 04/14/2006 06/05/2006 06/10/2006 07/05/2006 07/06/2006 02/13/2007 02/14/2007 09/04/2007 09/07/2007 09/26/2007 09/26/2007 10/13/2007 10/14/2007 06/29/2008 07/04/2009 09/22/2008 09/26/2008 10/22/2008 10/22/2008

Attachment L-11-335 Page 6 of 12 10/24/2008 10/24/2008 07/13/2009 07/13/2009 07/27/2009 07/31/2009 08/17/2009 08/24/2009 12/29/2009 12/30/2009 05/24/2010 05/25/2010 09/27/2010 09/27/2010 09/26/2011 09/28/2011 09/29/2011 Unit 1 Unit 2 22 Outages 15 Outages However, further evaluation of the issue has identified that cyclic history may not have been as prevalent a failure mode as originally identified in FENOC Letter L-11-333. An "Analysis of Transformer Failures" by The Hartford Steam Boiler Inspection & Insurance Co. performed a 5-year study of large transformer failures. The study identified the following causes of transformer failures as most prevalent.

Cause of Failure Number Insulation Failure 24 Design/Material/Workmanship 22 Unknown 15 Oil Contamination 4 Overloading 5 Fire/Explosion 3 Line Surge 4 Improper Maintenance/Operation 5 Flood 2 Loose Connection 6 Lightning 3 Moisture 1 Total 94 Therefore, predictive maintenance monitoring such as DGA (including oil analysis) is expected to be effective in identifying insulation failures, oil contamination, and moisture. External factors such as flooding, lightning, line surges and fire/explosion are outside FENOC control. Startup transformers are lightly loaded which would be expected to eliminate the factor of overloading.

Loose connections could be identified through thermography predictive monitoring. Design, material, workmanship and improper maintenance/operation are the remaining two factors of potential concern. The Unit 2 startup transformer has been in service since 1984. A design/workmanship issue was resolved in 2000 when it was identified that the corona rings were missing on the 345kV

Attachment L-11-335 Page 7 of 12 bushings. All three bushings were replaced and corona rings were procured and installed. This workmanship issue occurred in 1996 when U type bushings, which were a known industry failure mechanism, failed, and were replaced on the Unit 2 startup transformer. No other major internal work on the Unit 2 startup transformer was identified since 2000. In conclusion, based on the prevalent failure modes of large transformers identified in the study, predictive monitoring technology implemented to preclude the identified failures, and maintaining the Unit 2 SUT energized until the Unit 1 SUT is returned to service, there is reasonable confidence that the Unit 2 SUT is suitable for continued service for the temporary LAR interval.

6. The detail results of dissolved gas analyses (DGA) were not provided. The RAI response indicates that the results of the Unit 2 start up transformer have been in accordance with IEEE C57.104-2008. The trending graphs submitted in response to the RAI indicate some spikes in gases that would indicate transformer problems. In addition, some gases (ethane and carbon monoxide) are showing an upward trend for Unit 2 start up transformer.

Provide details on actions that were taken for the high gas values that were observed in the DGA to ensure that the transformers will perform its intended function during plant operation.

Response: The sudden increase in combustible gases in October 2000 was due to a Unit 2 startup transformer fault because the corona ring was not installed on the "B" phase bushing. The bushings were replaced and the transformer restored. Follow-up DGA analysis indicated all parameters were within their required band.

During the 1998 timeframe, though other gases such as nitrogen and oxygen were at an increased level during one sampling period, these gases are not combustible gases in accordance with IEEE C57.104-2008 and no trigger levels are established for increased conditional monitoring. The noted parameters returned to normal levels at the next sampling period.

Some gases such as methane, carbon monoxide and ethane have shown an overall upward trend since 2000. However, the actions prescribed in IEEE C57.104-2008 were not taken because the trigger point for the identified gases had not been reached. The DGA data is monitored and trended by the system engineer who evaluates the data holistically based on the IEEE standard guidance. Currently, an upward trend that is below the IEEE trigger point would not typically result in a change in DGA frequency if the remaining key parameters are within band. As an example, moisture content exceeded the established trigger point in December 2010. The DGA preventive maintenance frequency was increased from bi-annual to quarterly in accordance with the IEEE guidelines. The quarterly sampling began in February 2011 and identified that methane had exceeded it's trigger value of 121 ppm which would have resulted in

Attachment L-11-335 Page 8 of 12 Condition 2 monitoring and consideration for an accelerated monitoring interval from bi-annual to quarterly. Since the monitoring frequency established was already at the quarterly interval, no additional action was taken. It should be noted that the following June 2011 sample had decreased below the established trigger point for methane. The DGA samples, however, continued to be monitored quarterly due to the condition monitoring originally established for moisture content. The most recent sample for moisture in August 2011 indicates moisture has decreased to within an acceptable band.

7. Referencing the gas analysis for the auxiliary transformer, explain the impact of the heightened level of ethane gas and the increasing trend in carbon monoxide level on the capability and reliability of the transformer.

Response: As referenced in IEEE C57.104-2008, Section 5, "Interpretation of Gas Analysis," a transformer that operates at or near its nameplate rating normally will generate several hundred ppm of carbon monoxide (CO) without excessive hot spots. The PNPP auxiliary transformer is normally loaded at 75 percent of nameplate with the levels for CO being below the IEEE trigger of 350 ppm. The highest level of CO was 101 ppm in January 2006. In accordance with IEEE guidance, there is no concern with the level of CO and no negative trend established.

The auxiliary transformer levels for ethane are also below its IEEE trigger value of 65 ppm with only two samples exceeding the trigger limit since 2006. The highest parameter sampled was 107 ppm on 6/3/09. The remaining samples of ethane are generally in the low to mid 40 ppm range. Per IEEE guidance, there is no concern with the level of ethane and no negative trend established.

8. The data provided by the licensee shows that the Class 1E batteries have been sized to support LOOP/LOCA conditions for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and SBO conditions for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Explain how the batteries are capable of mitigating a design basis event for the time period needed to establish the backfeed circuit (129 minutes). In your response, provide details on how the SBO loads bound those required for LOOP/LOCA (SBO assumes non-accident conditions).

Response: FENOC performed a design basis 4-hour station blackout (SBO) battery capacity calculation for PNPP. The following methodologies used in this SBO calculation also bound the analysis for the loss of offsite power/loss of coolant accident (LOOP/LOCA) loading conditions.

a. The Division 1 and 2 normal and reserve battery chargers are not available due to total loss of AC power (TLAC).

b. Offsite power remains unavailable for the entire SBO.

c. The Division 1 and Division 2 battery continuous loads during a design basis 4-hour SBO have been conservatively assumed to be the same as those during a 2-hour design basis LOOP/LOCA scenario.

Attachment L-11-335 Page 9 of 12 Based on the methodologies of items a through c above, the SBO analysis bounds the requirements of a LOOP/LOCA event.

USAR Table 8.3-7 provides a listing of required DC loads for a loss of AC power coincident with a LOCA and their required time sequence. These loads are used in the associated battery calculations.

During a SBO event, Unit 1 batteries will supply the connected loads for the first 35 minutes. In accordance with FENOC procedures, the Unit 1 and 2 batteries will be cross-tied and operating in parallel after 35 minutes.

By procedure, nonessential (non-critical) loads will be shed from the Division 1 and 2 batteries by opening disconnect switches and molded case circuit breakers within three hours (180 minutes) of the SBO event.

A FENOC calculation shows that the Division 1 and Division 2 diesel generator supply breakers or preferred supply breakers or alternate preferred supply breakers will operate at t = 239 minutes and 59 seconds and the corresponding emergency diesel generator will start, thus exiting the 4-hour SBO.

Based on the LOOP/LOCA loads being analyzed for four hours, there is adequate margin to establish the backfeed circuit in 129 minutes.

9. The response implies that the load flow analyses were performed for post LOCA steady state conditions.

a. Validate that the limiting case for voltage drop analyses using the backfeed circuit is the post LOCA steady state condition and not a controlled shutdown of the plant with normal auxiliary loads and shutdown loads in operation.

Response: As identified in a FENOC calculation, the limiting case for the voltage drop analysis using the backfeed circuit is POSTLOCABFD. This case analyzes the post-LOCA loading (with manual loads) skewed to Division 1, with stub bus loads removed. Backfeed is through the auxiliary transformer to bus L12, then to bus L10 to supply power to the ESF buses through the Unit 1 interbus transformer. The backfeed source will be implemented per a FENOC procedure, thus the loads will be at post-LOCA steady state conditions.

Per the FENOC calculation, case POSTLOCA_BFD is not dependent upon how the shutdown occurred (i.e., controlled or not a controlled shutdown), but the need to supply power to the safety buses to permit the operation of those electrical loads needing to support plant post-LOCA conditions.

The minimum grid voltage is defined as the minimum value for the PNPP 345 kV switchyard voltage at which the offsite sources can be considered functional.

Specifically, the minimum grid voltage corresponds to the minimum PNPP 345 kV switchyard voltage at which a LOCA actuation can occur and the safety loads automatically load sequentially without transferring to the emergency diesel generators. The minimum grid voltage could occur at anytime, even when

Attachment L-11-335 Page 10 of 12 connecting to the grid to establish the backfeed circuit due to a LOOP. Thus, the minimum grid voltage has to be able to supply the loads which would have been supplied by the emergency diesel generators, post LOOP. This has been analyzed in a degraded voltage calculation and is designated case A. Per the calculation, case A establishes the analysis level for minimum grid voltage. Thus, post-LOCA, the case A voltage drop analysis bounds the backfeed LOOP voltage drop analysis.

b. Provide a listing and rating of loads on the plant busses that would be operating for the limiting case.

Response: The listing and rating of loads on the plant busses that would be operating for the limiting case are located in a FENOC calculation. This calculation is available on-site for NRC review.

c. Validate that the degraded voltage relay setting is acceptable for large motor starts that may occur during controlled plant shutdown (refer RAI 2 Page 4 of 9)

Response: The degraded voltage relay settings are acceptable for large motor starts when using the backfeed. The settings are established in a 4.16 kV degraded voltage instrumentation loop tolerance calculation. This FENOC calculation establishes the setpoint parameters for the Division 1, 2 and 3 degraded voltage relays and their associated time delay relays. Input to this calculation is provided by a separate calculation that establishes the analysis level for minimum grid voltage of 0.96 per unit and bounds the degraded voltage relay settings which would have been established just for large motor starts when using the backfeed.

The degraded voltage analysis performed in the calculation is used to demonstrate that the loads running post-LOCA actuation on the ESF buses have adequate voltage down to the analytical limit for dropout (trip) of the Class IE 4.16 kV degraded voltage relays, including use of the backfeed circuit.

Therefore, the degraded voltage relay settings are acceptable for large motor starts that may occur during a controlled plant shutdown.

Attachment L-11-335 Page 11 of 12

10. The response indicates that SBO loading on the DC system is less than the LOOP/LOCA loading. Verify that an ECCS actuation signal would not be generated at the onset of a station blackout such that ECCS loads will be given an actuation but will not operate if they are AC powered. All DC loads such as EDG starting circuit, DC MOVs etc. that may have a start signal have been accounted for in the loading analyses. The response also indicates that the sizing criteria shows adequate design margin. Verify the battery capacity based on the actual performance observed during the last surveillance test. (ref. RAI 3 d Page 9 of 9)

Response: Within the SBO calculation, the Division 1 and Division 2 battery continuous loads during the 4-hour SBO have been conservatively assumed to be the same as those used within the 2-hour Division 1 and Division 2 design basis LOOP/LOCA calculations.

A probabilistic risk analysis study indicates that at the onset of an SBO without onsite AC power, reactor water level is maintained above the reactor pressure vessel setpoint such that the LOCA emergency core cooling system (ECCS) logic would not be actuated. The reactor core isolation cooling (RCIC) system is credited in the response to this event. Since an actual LOCA is not postulated, drywell pressure is also not expected to increase to its LOCA logic setpoint.

Thus, a LOCA ECCS actuation signal is not anticipated to be actuated at the onset of an SBO event.

The capacity of the batteries was last verified on the dates noted below:

Division 1, Unit 1 battery - analyzed and found acceptable on 1/13/09 Division 1, Unit 2 battery - analyzed and found acceptable on 3/24/10 Division 2, Unit 1 battery - analyzed and found acceptable on 12/18/09 Division 2, Unit 2 battery - analyzed and found acceptable on 2/23/10

Attachment L-11-335 Page 12 of 12

11. Provide details on the protective relaying associated with the main transformer and the transmission lines emanating from the main transformer. Provide a summary of the analyses performed to evaluate the relay performance when using the backfeed circuit and include details on the inrush current that was considered when the main transformer and unit auxiliary transformers are energized simultaneously from the grid with no support from the main generator. Also provide details on any impact on current sensing devices (potential transformers, current transformers, etc.)

that will be sensing current in the reverse direction. Identify relays that will be disabled as a consequence of opening the disconnect switch and level of protection that will be afforded after opening the disconnect switch.

Response: As identified on FENOC drawings, the protective relaying associated with the main transformer and transmission lines emanating from the main transformer are differential relays.

The main transformer is protected by additional relaying that includes overcurrent relays, an instantaneous overcurrent relay, a blocking relay, and a sudden pressure relay.

The same level of protection is afforded during forward or backfeed transmission.

Therefore, no additional analysis is required to evaluate the relay performance for the backfeed circuit. The protective relay setpoints do not require readjustment when using the backfeed circuit.

The offsite power will be restored via the backfeed circuit by procedure. The adequacy of the offsite transmission system back-feeding through the main transformer and the unit auxiliary transformer, as an alternative offsite source, is evaluated in a FENOC calculation. Within the calculation, case LOCAMS1A is the most limiting motor starting case. It bounds the post-LOCA backfeed case, PostLOCA_BFD. Motor starting case LOCA_MS1A includes the stub bus loads, which were excluded from case PostLOCA_BFD. This case is modeled with the Unit 1 and Unit 2 loads powered from the Unit 2 startup transformer with bus EH21 powered through bus LIO. Thus, no additional analysis was performed to evaluate the inrush current during this post-LOCA demand loading.

The current sensing devices (that is, current transformers) are non-directional; therefore, they are unaffected by the reverse in current flow during a backfeed alignment.

There will be no relays disabled as a consequence of opening the main generator disconnect switch.

There will be no change in level of protection when the main generator disconnect switch is opened.