ML093070294
| ML093070294 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 09/16/2009 |
| From: | Plona J Detroit Edison |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NRC-09-0054 | |
| Download: ML093070294 (12) | |
Text
Joseph H. Plona Site Vice President 6400 N. Dixie Highway, Newport, MI 48166 Tel: 734.586.5910 Fax: 734.586.4172 DTE Energy-10 CFR 50.90 September 16, 2009 NRC-09-0054 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington D C 20555-0001
References:
- 1) Fermi 2 NRC Docket No. 50-341 NRC License No. NPF-43
- 2) Detroit Edison's Letter to NRC, "Proposed License Amendment to Revise the Degraded Voltage Function Requirements of Technical Specification Table 3.3.8.1-1 to Reflect Undervoltage Backfit Modification,"
NRC-09-0022, dated June 10, 2009
Subject:
Response to Request for Additional Information Regarding the Proposed License Amendment to Revise the Degraded Voltage Function Requirements of Technical Specification Table 3.3.8.1-1.to Reflect Undervoltage Backfit Modification In Reference 2, Detroit Edison proposed a license amendment to revise Technical Specification Table 3.3.8.1-1 to reflect changes necessitated by a degraded voltage logic, design modification developed to address an NRC backfit issue. The NRC reviewed the proposed license amendment and requested additional information in an e-mail from Mr. Mahesh Chawla to Mr. Alan Hassoun dated July 27, 2009. This was discussed in a subsequent telephone conversation between NRC staff and Detroit Edison personnel on July 30, 2009. The additional information requested by the NRC staff is enclosed.
There are no new commitments included in this document.
Should you have any questions or require additional information, please contact Mr.
Rodney W. Johnson of my staff at (734) 586-5076.
Sincerely,
USNRC NRC-09-0054 Page 2 Enclosure cc: NRC Project Manager NRC Resident Office Reactor Projects Chief, Branch 4, Region III Regional Administrator, Region III Supervisor, Electric Operators, Michigan Public Service Commission
USNRC NRC-09-0054 Page 3 I, Joseph H. Plona, do hereby affirm that the foregoing statements are based on facts and circumstances which are true and accurate to the best of my knowledge and belief.
Joseph H. Plona Site Vice President, Nuclear Generation On this _
day of
,, 2009 before me personally appeared Joseph H. Plona, being first duly sworn and says that he executed the foregoing as his free act and deed.
Notary Public AN S. kARSHALL NOTARY PUJBJc, STATE OF Ix OMOU1YFONROE MYCOMMISSION EXPIRES Jun 14,0.
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ENCLOSURE TO NRC-09-0054 FERMI 2 NRC DOCKET NO. 50-341 OPERATING LICENSE NO. NPF-43 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION (RAI)
REGARDING THE PROPOSED LICENSE AMENDMENT TO REVISE THE DEGRADED VOLTAGE FUNCTION REQUIREMENTS OF TECHNICAL SPECIFICATION TABLE 3.3.8.1-1 TO REFLECT UNDERVOLTAGE BACKFIT MODIFICATION
Enclosure to NRC-09-0054 Page 1 The following is Detroit Edison's response to each NRC request for additional information (RAI):
- 1.
Provide summary and conclusions of the latest plant calculations/analysis, which justifies the voltage and time delay settings associated with the degraded voltage function. Provide basis of minimum switchyard voltage assumed in the calculations for the degraded voltage setpoints.
Response
Degraded voltage relay setpoints and time delay setpoints are established in design calculation DC-0919, Volume I, and in pending change documents to reflect the design of the planned modification. The calculations utilize a verified model of the Fernmi 2 electrical distribution system within the ETAP software. The ETAP model evaluates the range of offsite voltages and corresponding essential bus voltages for which safety related equipment can continuously operate. The ETAP software is widely used in the industry for electrical system analyses.
The minimum offsite voltage on the Division I, 120kV system for which large motors can start and all safety related equipment can operate continuously with Load Tap Changer (LTC) operation on Transformer SS64 is 93.3%. The minimum offsite voltage on the Division II, 345kV system for which large motors can start and safety related equipment can operate continuously is 98.4%.
Voltage Setpoints for Degraded Voltage Relays Minimum continuous and transient operating voltages for plant loads and distribution equipment are established and used in the identification of degraded voltage setpoints.
Voltage boundaries for essential 4160 V buses have been established in DC-0919, Volume I to ensure an adequate voltage operating range is provided to all essential devices. The degraded voltage relay setpoints are derived with consideration of equipment minimum operating voltage requirements, minimum steady state bus voltages, and transient voltage dips associated with motor starting. At the low end of the relay setpoint band (3873 V for Division I and 3628 V for Division II), a few safety related buses may operate slightly below their lower voltage boundaries; however, all safety related devices will still be provided with terminal voltage above their specified minimum rated voltage.
The existing evaluations for degraded voltage without a Loss of Coolant Accident (LOCA) consider a degraded voltage relay trip band of t 2% of the setpoint value with a reset value of 103% of pickup, consistent with vendor information for the existing ABB 27D relays. An evaluation of relay setpoints, minimum time delay, and bus voltage recovery for degraded voltage with LOCA utilizes a reset value of 101%, based on the replacement of the existing ABB 27D relays with ABB 27N relays in conjunction with the modification to add the LOCA degraded voltage time delay logic. The setpoint accuracy of the new relays is also equal to or better than the original degraded voltage relays.
Enclosure to NRC-09-0054 Page 2 For Division I, load tap changer operation on Transformer SS64 maintains the 4160 V essential bus voltage at 100% +/- 1% for a range of input voltages from +10% to -20% of the 120kV nominal system grid voltage. This range of operation bounds the lower limit of 112kV (93.3%) at the 120kV bus. The LTC maintains the Division I essential bus voltage at acceptable levels when the 120kV system is at or above the calculated low voltage limit.
Degraded voltage is sensed for trip relaying at the 4160 V essential buses (64B and 64C).
The degraded voltage trip setpoint is selected based on the minimum bus voltage boundary for these buses, i.e., the degraded voltage level at which equipment can safely operate without damage. The setpoint selected in this manner is 95% of the 4160 V bus voltage +/-
2%, and is the same as specified in the current Technical Specifications.
For Division II, Transformer SS65 is not equipped with a load tap changer. For the degraded voltage relay setpoint, steady state 4160 V bus voltage is the limiting criteria, as Division II essential 480 V buses have voltage regulators that lessen the impact of degraded grid for steady state operation at the low voltage level. The grid low voltage operating limit is 98.4%, which corresponds to 95.1% of nominal 4160 V bus voltage at essential buses 65E and 65F for the loading conditions analyzed. This is the pre-start voltage for evaluation of motor starting transients. The evaluation demonstrates that safety related loads can be started and operated from offsite power system at these voltage levels. Degraded voltage is sensed for trip relaying at the 4160 V essential buses (65E and 65F). The degraded voltage trip setpoint is selected based on the minimum bus voltage boundary for these buses. The setpoint selected in this manner is 89% of the 4160 V bus voltage +/- 2%, and is the same as specified in the current Technical Specifications.
Time Delay for Degraded Voltage (Without LOCA)
Trip time delay for Division I degraded voltage (without LOCA) is established in calculation DC-0919, Volume I based on an evaluation of transient voltages associated with large motor starting. For Division I, the time delay is based on an initial grid voltage of 93.3% with an initial 4160 V bus voltage of 100% and the start of two Residual Heat Removal (RHR) pumps, with two Core Spray pumps starting five seconds later. Based on Transformer SS64 LTC operation, the time delay is established as 44 seconds with a lower limit of 41.8 seconds and an upper limit of 46.2 seconds. The time delay is based on a 20 second delay until LTC operation begins and ten LTC step changes at two seconds each until voltage recovery above the setpoint. The total time delay includes a 10% margin (4 seconds). The degraded voltage alarm for Division I is 98% of 4160 V bus voltage with a 30 second delay. This alarm alerts the control room operator of a potential degraded voltage condition and a potential problem with the Transformer SS64 load tap changer.
For Division II, time delay is based on an initial grid voltage of 98.4% (corresponding to a 4160 V bus voltage of 95.1%) and the start of two RHR pumps, with two Core Spray pumps starting five seconds later. Static motor starting analysis and bus voltage response shows that bus voltage recovers to a level above the degraded voltage reset value in 18.5 seconds.
The lower limit of the time delay is selected as 20.4 seconds, which includes a 10% margin.
The degraded voltage alarm setpoint is 98.4% of the 4160 V bus voltage with a ten second
Enclosure to NRC-09-0054 Page 3 time delay. The alarm alerts the control room operator of the potential degraded voltage condition.
No change is proposed to the current Technical Specification time delays when a LOCA signal is not present.
Time Delay for Degraded Voltage With LOCA A modification is planned to be installed during the upcoming refueling outage to add new relay logic for degraded voltage with LOCA. The modification involves a time delay relay in parallel with the existing time delay relay for degraded voltage (without LOCA). The new logic has a shorter time delay and initiates load shedding after that time if a LOCA signal is present. As such, the same degraded voltage relays (and setpoints) are used for degraded voltage protection with or without LOCA. The existing ABB 27D degraded voltage relays are to be replaced with ABB 27N relays in conjunction with the modification to add the LOCA time delay logic. The reset for these replacement relays is selected at 101% of the trip value, which is an improvement from the 103% reset for the existing relays. This lower reset value is utilized in the evaluation of the time delay for degraded voltage with LOCA.
The time delay for a degraded voltage with LOCA is established in pending changes to calculation DC-0919, Volume I for the new degraded voltage time delay. The time delay is selected based on the following:
a) The maximum time delay which provides load shed and Emergency Diesel Generator (EDG) breaker closure (with RHR pump motor start) at or less than 10 seconds, consistent with the accident analysis.
b) The minimum time delay that allows sequential starting of LOCA loads without separating from the offsite power supply.
For a degraded voltage that exists prior to a LOCA signal, the timer may have partially or completely timed out, such that the time delay following LOCA is minimized. When degraded voltage has been present for a nominal 8 seconds before a LOCA, a degraded voltage trip will be immediately initiated. The longest time delay until load shed occurs when a LOCA signal is initiated at the same time as the degraded voltage timing start. A revision to calculation DC-0919, Volume I is included in the modification package to install the new time delay logic. It shows that the total time delay associated with the proposed upper Technical Specification value of 8.4 seconds, including consideration for setpoint drift and instrument error and a one second time delay for load shedding, is less than the ten second time period identified in the accident analysis from the time a LOCA signal is sensed to EDG breaker closure and RHR pump start.
With respect to minimum time delay before load shedding, an ETAP evaluation of bus voltage dips during sequenced starting of the RHR and Core Spray pump motors has been
Enclosure to NRC-09-0054 Page 4 performed. This evaluation is described in the answer to question 3.a. The details of this evaluation are included in the pending changes to calculation DC-0919, Volume I for the new time delay logic modification package. As stated in the answer to question 3.a, for both Division I and Division II essential buses the analysis indicates that the voltage dips below the degraded voltage relay setpoint during RHR pump starting and recovers to reset the relay prior to Core Spray pump starting. The voltage dip for Core Spray pump starting is also expected to pick up the degraded voltage relay and recover to a level above the relay reset. Using the proposed minimum Technical Specification value of 7.6 seconds and including consideration for setpoint drift and instrument error, the minimum time delay associated with the lower value for the proposed Technical Specification change is greater than seven seconds. For both Division I and Division H, the minimum delay for degraded voltage trip is greater than the longest time to degraded voltage relay reset, such that LOCA loads may be started at the minimum grid operating voltage of 93.3% of nominal grid voltage for Division I (based on LTC operation) and 98.4% of nominal grid voltage for Division II.
- 2.
Describe and provide applicable logic diagrams to show how the degraded voltage function interfaces with emergency diesel generator (EDG) system, loss-of-coolant accident (LOCA) signal, and load sequencer.
Response
Degraded voltage is monitored and load shedding is initiated at the 4160 V essential buses in the Reactor Building (64B, 64C, 65E, and 65F). Monitoring and load shedding is specific to each of these essential buses and includes shedding the 4160 V essential buses associated with each of the four EDGs (buses llEA, 12EB, 13EC, and 14ED). Load shedding initiated by degraded voltage (DV) relaying is independent of load shedding initiated by loss of voltage (UV) relaying. As part of the load shedding scheme for the respective essential bus (for either loss of voltage or degraded voltage and time delay), an input is provided to the EDG sequencer after the associated time delay. Other inputs to the EDG load sequencer include the LOCA signal and EDG breaker position. The DV or UV signals have to be present when the EDGs come up to speed and are ready to load in order to shed loads and power the essential loads from the EDGs.
During load shedding, starting of sequenced loads is blocked by the sequencer. Sequencing of loads is initiated by EDG breaker closure and starting of specific loads is controlled by a combination of sequencer output and relay operation within the respective breaker control logic. At time T=0, the sequencer enables starting of the RHR pump and the Core Spray pump. The RHR pump starts without delay, in response to the LOCA signal when adequate voltage is present at the respective essential bus (64B, 64C, 65E, or 65F). Control logic for the Core Spray pumps includes a five second time delay after both a LOCA signal and reset of the UV or DV lock out relay for the respective essential bus (64B, 64C, 65E, or 65F).
The EDG breaker control logic includes a one second time delay in the breaker close circuit following initiation of load shedding. The EDG load sequencer logic also includes a one second delay following initiation of load shedding.
Enclosure to NRC-09-0054 Page 5 Starting of the RHR and Core Spray pump motors in response to a LOCA signal without undervoltage (loss of voltage or degraded voltage) is controlled by specific relaying within the motor control circuits. The RHR pumps start without delay in response to the LOCA signal (High drywell pressure or low reactor level). The core spray pumps start five seconds after LOCA signal.
The following additional reference material is provided on a compact disc (CD):
" Undervoltage relaying and load shed schematics - I-N-2572-17, 19
- EDP Index Items 35621.B005 through B012
- RHR System logic and motor control (Pump A) 2205-02 and 03, 1-2201-01
" Core Spray System logic and motor control (Pump A) 2211-01, 1-2215-02
" EDG Sequencer logic 2714-22 through 25, 35 and 36
" EDG Breaker control schematic (EDG 11) - I-N-2572-11
- 3.
The License Amendment Request (LAR) states the amendment is for a degraded voltage concurrent [emphasis added] with a LOCA.
- a. With the minimum switchyard voltage conditions during LOCA and with the new time delay logic of degraded voltage function, confirm all safety-related loads will successfully sequence to meet the requirement of accident mitigation without tripping the degraded voltage relays.
Response
The associated safety buses of Division I are connected to a transformer that has a Load Tap Changer (LTC). The range of the LTC will allow the Division I voltage to be maintained at a nominal 4160 volts if the grid voltage degrades to the 93.3% limit. The associated safety buses of Division II can operate satisfactorily at the switchyard low voltage limit of 98.4%.
Both Division I and Division II can successfully withstand a LOCA start signal to the RUR and Core Spray pumps at these voltage levels without causing a grid separation due to degraded voltage.
The degraded voltage alarm for Division I provides an annunciation in the control room at 98% of 4160 V bus voltage with a 30 second time delay. The alarm setpoint for Division II, also annunciated in the control room, is 98.4% of 4160 V bus voltage, with a 10 second time delay.
Division I The safety buses of Division I are connected to Transformer SS64 which is equipped with a Load Tap Changer (LTC) to regulate the safety related buses to 4160 volts. The range of the LTC will allow the Division I voltage to be maintained at a nominal 4160 volts when the
Enclosure to NRC-09-0054 Page 6 120 KV grid is at the degraded grid voltage limit of 112KV (93.3%). The automatic LTC operation is required for voltage recovery. This is due to the high reset value of the installed degraded voltage relays. Additionally the transient stability study contained within DC-0919, Volume I shows the acceleration time of the Core Spray pumps to be approximately 12 seconds. These analyzed values support voltage recovery on the safety buses when the nominal 44 second time delay is in the circuit because this allows the LTC time to operate and increase the voltage.
The existing design basis contained in DC-0919, Volume I relies on a transient stability study which shows the Core Spray pump acceleration time at approximately 12 seconds based on full load flow required immediately after start. This full flow condition applies to both the RHR and Core Spray pumps. This analysis uses full rated motor horsepower (HP) to produce worst case voltage dips, recovery voltages and acceleration times. The installation of the new time delay logic will add a second parallel trip circuit. This parallel trip circuit will actuate after a nominal 8 second time delay when a sustained degraded voltage is present and will cause a trip when a LOCA signal is present.
A review of actual conditions during RHR and Core Spray motor starts with a LOCA, supports the use of lower HP requirements prior to vessel depressurization due to minimum flow conditions. The ETAP dynamic motor starting model was used to verify the original analysis and develop refined voltage dips and acceleration curves. This ETAP analysis used horsepower levels consistent with RHR and Core Spray pump flow conditions when starting in response to a LOCA signal. The acceleration parameters, inertia values, starting torque, load torque and acceleration times were based on current system design calculations and vendor data. The ETAP Model acceleration times were also verified against response times during Loss of Power (LOP)/LOCA testing on the EDGs. The power requirements were based on the vendor supplied pump curves.
The results of the ETAP dynamic motor starting analysis indicate that the Core Spray motor acceleration time will be less than 7 seconds. This acceleration time is consistent with data obtained during testing. The modification to install the new LOCA time delay logic is being installed in conjunction with the modification to replace the existing ABB 27D degraded voltage relays with ABB 27N degraded voltage relays. The reset value associated with the new relay allows a worst case reset of 101% of the maximum setpoint value (102% of 95%),
or 97.87% of Division I bus voltage. This supports continued operation on the grid for Division I on a LOCA start of the RHR and Core Spray pump motors. The Division I ETAP analysis shows that Division I will be able to operate at the low voltage grid limit of 93.3 %
and successfully withstand a LOCA start signal to the RHR and Core Spray pumps without causing a grid separation due to degraded voltage. This occurs because the voltage recovery is sufficient to allow resetting of the ABB 27N degraded voltage relay after the RHR pumps start and after the Core Spray pumps start. This new analysis is documented in pending changes to DC-0919, Volume I.
Enclosure to NRC-09-0054 Page 7 Division II The current analysis in DC-0919, Volume I indicates that Division II can operate to the low voltage grid limit of 98.4% and successfully withstand a LOCA start signal to the RHR and Core Spray pumps without causing a grid separation due to degraded voltage with the current nominal 21.4 second time delay. This occurs because the voltage recovery is sufficient to allow resetting of the DV relay after Core Spray pump motor starts.
The new dynamic analysis indicates that Division II can operate to the low voltage grid limit of 98.4% and successfully withstand a LOCA start signal to the RHR and Core Spray pumps without causing a grid separation due to degraded voltage with the proposed 8 second time delay. This occurs because the voltage recovery is sufficient to allow resetting of DV relay after RHR pump motor starts. On the start of the Core Spray pump motors the voltage dip will again pick up the DV relay, but it will reset prior to the.seven second minimum delay for the degraded voltage trip scheme. This voltage recovery reset for both the RHR and Core Spray is based on the installation of the new ABB 27N degraded voltage relays.
- 3.
The LAR states the amendment is for a degraded voltage concurrent [emphasis added]
with a LOCA.
- b. If the degraded voltage relay trip occurs within 7.6 seconds to 8.4 seconds (proposed time delay settings) of the LOCA signal, explain how running loads will safely transfer to the EDG.
Response
The time delay is selected such that load shedding as a result of degraded voltage relay trip is completed to allow EDG breaker closure to occur at or before ten seconds from the receipt of a LOCA signal, consistent with the accident analysis as discussed in UJFSAR Section 15. This includes the one second time delay within the EDG breaker close circuit to allow for completion of load shedding. Details of the time delay evaluation are included in calculation DC-0919, Volume I, as revised in the modification package to install the new LOCA time delay logic. The calculation demonstrates that EDG breaker closure occurs at or before ten seconds following an initiation of a LOCA signal, including consideration for relay repeatability and instrument error.
Both the existing nominal time delay relaying (44 seconds for Division I and 21.4 seconds for Division II) and the eight second time delay logic added by the degraded voltage modification package are actuated for a voltage below the degraded voltage relay setpoint, regardless of the existence of a LOCA signal. Load shedding is initiated immediately if a LOCA signal exists or occurs after the eight second time delay. The longest delay from a LOCA signal to degraded voltage relaying trip and load shed occurs when a LOCA signal is received at the same time as the degraded voltage timing start. The resulting sequence is as follows:
Enclosure to NRC-09-0054 Page 8 a) The RHR pump motors start without delay upon a LOCA signal while connected to offsite power. The EDGs are also started upon a LOCA signal.
b) The Core Spray pump motors start on offsite power after a five second delay.
c) After a delay of 7.6 to 8.4 seconds (with bus voltage below the degraded voltage setpoint) the load shedding is started, including trip of the incoming breaker for offsite power to the essential buses (64B, 64C, 65E, or 65F). This also includes tripping of the RHR and Core Spray pump motors, if energized.
d) EDG breaker closure occurs after EDG speed and voltage are achieved and load shedding is completed. A one second time delay relay in the EDG breaker close circuit and also in the load sequencer is used to allow completion of load shedding prior to EDG breaker closure.
e) The RHR pump motors restart following this time delay, upon EDG breaker closure.
f) The Core Spray pump motors start (or re-start) after a five second delay.
The RHR and Core Spray pump motors trip and are re-started on the respective EDG in response to a combination of load sequencer logic and motor start logic. During the period after load shedding until EDG breaker closure, motor starting is blocked by the EDG load sequencer. The RHR pump motor re-start occurs a minimum of one second after tripping while the motors are running. In this instance, the trip occurs approximately 8.4 seconds after starting, such that motor starting is complete. Motor trip during starting would involve a longer delay before re-start. The delay from Core Spray motor trip until restart is at least six seconds, including the one second delay associated with load shedding and the five second delay following EDG breaker closure.
Overcurrent relay settings for the RHR and Core Spray pump motors are established in a separate design calculation and include margin to prevent tripping for motor restart.