Text

Units 1 & 2 - License Amendment Request to Install New Low Degraded Voltage Relays & Timers on the 4.16 Kv Engineered Safety Features (ESF) Buses
	ML14120A039
Person / Time
Site:	Byron, Braidwood
Issue date:	04/24/2014
From:	Gullott D; Exelon Generation Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML14120A038	List: ML14120A039; ML14120A040; ML14120A041;
References
	RS 14-116 IR-10-003
	Download: ML14120A039 (45)
	v • d • e

Exepon Generation RS-14-116 10 CFR 50.90 April 24, 2014 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Braidwood Station, Units 1 and 2 Facility Operating License Nos. NPF-72 and NPF-77 NRC Docket Nos. STN 50-456 and STN 50-457 Byron Station, Units 1 and 2 Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455

Subject:

License Amendment Request to Install New Low Degraded Voltage Relays and Timers on the 4.16 kV Engineered Safety Features (ESF) Buses

Reference:

Letter from R. A. Skokowski (NRC) to M. J. Pacilio (Exelon Generation Company, LLC), "Byron Station, Units 1 and 2, Integrated Inspection Report 05000454/2010003; 05000455/2010003," July 27, 2010 In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit or early site permit," Exelon Generation Company, LLC, (EGC) requests amendments to Facility Operating License Nos. NPF-72 and NPF-77 for Braidwood Station, Units 1 and 2, and Facility Operating License Nos. NPF-37 and NPF-66 for Byron Station, Units 1 and 2. This amendment request proposes to revise Technical Specifications (TS) 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation." Specifically, LCO 3.3.5 would be revised to add a new "low degraded voltage" Function; and the associated Surveillance Requirement (SR) 3.3.5.2 would also be revised to add a CHANNEL CALIBRATION to verify the specified values for the new low degraded voltage Allowable Value and time delay setting.

As documented in the referenced letter, Byron Station received a Green Finding with associated Non-cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for not having an appropriate analysis for the second level undervoltage (i.e., degraded voltage) relay timer setting, currently specified in SR 3.3.5.2, Item b. Specifically, Byron Station's analysis, documented in Engineering Change (EC) 377631, "Evaluation and Technical Basis for the AP

[Auxiliary Power] System Second Level Undervoltage (Degraded Voltage) Time Delay Settings,"

dated February 3, 2010, did not adequately confirm the ability of the 4.16 kV ESF bus safety-related loads to continue to operate for 5 minutes and 40 seconds (i.e., the degraded voltage time delay period prior to being isolated from the normal off-site power source) without sustaining damage during a worst case, non-accident degraded voltage condition. Consequently, TS 3.3.5 is considered to be a non-conservative TS. This issue is also applicable to Braidwood Station.

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April 24, 2014 U. S. Nuclear Regulatory Commission Page 2 It has been determined that a modification will be installed to resolve this concern. This modification will add new "low degraded voltage relays" (LDVRs) and timers (i.e., a third level of undervoltage protection), with appropriate settings, on each ESF bus. The calculations supporting the addition of these new relays and associated settings are presented in Attachments 4 and 5 for Braidwood Units 1 and 2; and Byron Station Unit 1 and 2 respectively.

The results of these calculations support the changes in this license amendment request and resolve the NRC concerns discussed in the referenced letter on a permanent basis. The addition of the LDVRs will continue to allow the existing undervoltage protection circuitry to function as originally designed; i.e., the first-level "loss of voltage" protection and the second-level "degraded voltage" protection will remain in place and be unaffected by this change. These new relays and timers will ensure the safety-related loads will not be damaged by appropriately isolating the safety-related loads (at 75% of nominal ESF bus voltage) from the normal off-site power source during a sustained degraded bus voltage event under non-accident conditions. The safety-related loads will then be re-sequenced back on to the 4.16 kV ESF buses as designed, powered by the Emergency Diesel Generator, and will continue to perform their design basis function.

Compliance with the intent of TS 3.3.5 is currently administratively controlled under the provisions of NRC Administrative Letter (AL) 98-10, "Dispositioning of Technical Specifications that are Insufficient to Assure Plant Safety," to assure that plant safety is maintained at both Braidwood and Byron Stations. This license amendment request is submitted in accordance with the guidance in AL 98-10. Consistent with the guidance in AL 98-10, EGC is submitting the proposed change as a required license amendment request to resolve a non-conservative TS. As such, this is not a "voluntary request from a licensee to change its licensing basis" and should not be subject to "forward fit" considerations as discussed in a letter from S. G. Burn (NRC, General Counsel) to E. C Ginsberg (NEI), dated July 14, 2010.

The attached request is subdivided as follows:

- provides a description and evaluation of the proposed changes.

- A provides the markup of the affected Braidwood Station TS pages.

- B provides the markup of the affected Byron Station TS pages.

- A provides the markup of the affected Braidwood Station Bases pages (for information only).

- B provides the markup of the affected Byron Station Bases pages (for information only).

- provides Braidwood Station Calculation 19-AN-29, Revision 002B, "Second-Level Undervoltage Relay Setpoint."

- provides Byron Station Calculation 19-AN-28, Revision 001 B, "CaIc. for Second-Level & Third-Level Undervoltage Relays."

The proposed amendment has been reviewed by the Braidwood Station and Byron Station Plant Operations Review Committees and approved by their respective Nuclear Safety Review Boards in accordance with the requirements of the EGC Quality Assurance Program.

In accordance with 10 CFR 50.91, "Notice for public comment; State consultation," paragraph (b),

EGC is notifying the State of Illinois of this application for license amendment by transmitting a copy of this letter and its attachments to the designated State of Illinois official.

April 24, 2014 U. S. Nuclear Regulatory Commission Page 3 EGC requests approval of the proposed license amendment request within one year of this submittal date; i.e., by April 24, 2015. Installation of the new relays and timers cannot be done on-line and will be installed during refueling outages. As the associated hardware will be installed over two outages on each unit, the amendment will be implemented on the following schedule:

Braidwood Unit 1:

Prior to MODE 4 following the Fall 2016 refueling outage (i.e., A1R19)

Braidwood Unit 2:

Prior to MODE 4 following the Fall 2015 refueling outage (i.e., A2R18)

Byron Unit 1:

Prior to MODE 4 following the Fall 2015 refueling outage (i.e., BIR20)

Byron Unit 2:

Prior to MODE 4 following the Spring 2016 refueling outage (i.e., B2R19)

There are no regulatory commitments contained in this letter. Should you have any questions concerning this letter, please contact Joseph A. Bauer at (630) 657-2804.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 2 4 th day of April 2014.

Respectfully, David M. Gullott Manager - Licensing Exelon Generation Company, LLC Attachments:

1.

Evaluation of Proposed Changes 2A.

Markup of Technical Specifications Pages - Braidwood Station 2B.

Markup of Technical Specifications Pages - Byron Station 3A.

Markup of Bases Pages - Braidwood Station 3B.

Markup of Bases Pages - Byron Station

4.

Braidwood Station Calculation 19-AN-29, Revision 002B, "Second-Level Undervoltage Relay Setpoint"

5.

Byron Station Calculation 19-AN-28, Revision 001 B, "CaIc. for Second-Level & Third-Level Undervoltage Relays" cc:

NRC Regional Administrator, Region III NRC Senior Resident Inspector, Braidwood Station NRC Senior Resident Inspector, Byron Station Illinois Emergency Management Agency - Division of Nuclear Safety

bcc:

Site Vice President - Braidwood Station Site Vice President - Byron Station Director - Licensing and Regulatory Affairs Manager - Licensing, Braidwood and Byron Stations Regulatory Assurance Manager - Braidwood Station Regulatory Assurance Manager - Byron Station Exelon Document Control Desk Licensing Commitment Tracking Coordinator - Midwest Murtaza Abbas (Braidwood)

Sam Ahmed (Braidwood)

Doug Spitzer (Byron)

Lisa Zurawski (Byron)

Gary Contrady (Byron)

ATTACHMENT 1 Evaluation of Proposed Changes

Subject:

License Amendment Request to Install New Low Degraded Voltage Relays and Timers on the 4.16 kV Engineered Safety Features (ESF) Buses 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION

3.0 TECHNICAL EVALUATION

3.1 Overview and Background 3.2

System Description

3.3 Proposed Modification and Technical Justification

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria 4.2 No Significant Hazards Consideration 4.3 Conclusions

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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ATTACHMENT I Evaluation of Proposed Changes 1.0

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit or early site permit," Exelon Generation Company, LLC, (EGC) requests amendments to Facility Operating License Nos. NPF-72 and NPF-77 for Braidwood Station, Units 1 and 2, and Facility Operating License Nos. NPF-37 and NPF-66 for Byron Station, Units 1 and 2. This amendment request proposes to revise Technical Specifications (TS) 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation." Specifically, LCO 3.3.5 would be revised to add a new "low degraded voltage" Function; and the associated Surveillance Requirement (SR) 3.3.5.2 would also be revised to add a CHANNEL CALIBRATION to verify the specified values for the new low degraded voltage Allowable Value and time delay setting.

As documented in a letter from R. A. Skokowski (NRC) to M. J. Pacilio (Exelon Generation Company, LLC), "Byron Station, Units 1 and 2, Integrated Inspection Report 05000454/2010003; 05000455/2010003," dated July 27, 2010 (Reference 1), Byron Station received a Green Finding with associated Non-cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for not having an appropriate analysis for the second level undervoltage (i.e., degraded voltage) relay timer setting, currently specified in SR 3.3.5.2, Item b. Specifically, Byron Station's analysis, documented in Engineering Change (EC) 377631, "Evaluation and Technical Basis for the AP [Auxiliary Power] System Second Level Undervoltage (Degraded Voltage) Time Delay Settings," dated February 3, 2010, did not adequately confirm the ability of the 4.16 kV ESF bus safety-related loads to continue to operate for 5 minutes and 40 seconds (i.e., the degraded voltage time delay period prior to being isolated from the normal off-site power source) without sustaining damage during a worst case, non-accident degraded voltage condition. Consequently, TS 3.3.5 is considered to be a non-conservative TS. This issue is also applicable to Braidwood Station.

It has been determined that a modification will be installed to resolve this concern. This modification will add new "low degraded voltage relays" (LDVRs) and timers (i.e., a third level of undervoltage protection), with appropriate settings, on each ESF bus. The calculations supporting the addition of these new relays and associated settings are presented in Attachments 4 and 5 for Braidwood Units 1 and 2; and Byron Station Unit 1 and 2 respectively.

The results of these calculations support the changes in this license amendment request and resolve the NRC concerns discussed in References 1 and 3 on a permanent basis. The addition of the LDVRs will continue to allow the existing undervoltage protection circuitry to function as originally designed; i.e., the first-level "loss of voltage" protection and the second-level "degraded voltage" protection will remain in place and be unaffected by this change.

These new relays and timers will ensure the safety-related loads will not be damaged by appropriately isolating the safety-related loads (at 75% of nominal ESF bus voltage) from the normal off-site power source during a sustained degraded bus voltage event under non-accident conditions. The safety-related loads will then be re-sequenced back on to the 4.16 kV EFS buses as designed, powered by the Emergency Diesel Generator (EDG), and will continue to perform their design basis function.

Compliance with the intent of TS 3.3.5 is currently administratively controlled under the provisions of NRC Administrative Letter (AL) 98-10, "Dispositioning of Technical Specifications that are Insufficient to Assure Plant Safety," (Reference 2) to assure that plant safety is maintained at both Braidwood and Byron Stations. This license amendment request is 2 of 21

ATTACHMENT 1 Evaluation of Proposed Changes submitted in accordance with the guidance in AL 98-10. Consistent with the guidance in AL 98-10, EGC is submitting the proposed change as a required license amendment request to resolve a non-conservative TS. As such, this is not a "voluntary request from a licensee to change its licensing basis" and should not be subject to "forward fit" considerations as discussed in a letter from S. G. Burn (NRC, General Counsel) to E. C Ginsberg (NEI), dated July 14, 2010.

EGC requests approval of the proposed license amendment request within one year of this submittal date; i.e., by April 24, 2015. Installation of the new relays and timers cannot be done on-line due to the short duration of the REQUIRED ACTION COMPLETION TIMES in the affected TS; therefore, the associated modifications will be installed when the units are offline during refueling outages. The modifications will be installed over two refueling outages on each unit as Byron and Braidwood Stations both utilize a "divisional outage" maintenance approach where only one train of ESF equipment is taken out of service for maintenance during a given refueling outage. This maintenance approach minimizes shutdown risk while ensuring that equipment is appropriately maintained. The proposed modification installation schedule is further supported by the existing compensatory actions to manually separate the ESF buses from the SATs upon confirmation that a degraded bus voltage condition exists (i.e., below 95.8 percent for Braidwood; 92.5 percent for Byron) in accordance with station alarm response procedures and NRC Administrative Letter 98-10. These manual operator actions are further discussed in Section 3.0 below.

The hardware supporting the proposed changes will be installed in accordance with 10 CFR 50.59, "Changes, tests, and experiments." The tripping capability for the new relays and timers will be left disconnected until approval and subsequent implementation of the proposed amendment. The subject hardware modifications will be installed on the following schedule:

Braidwood Unit 1:

Braidwood Unit 2:

Byron Unit 1:

Byron Unit 2:

Spring 2015 refueling outage (i.e., Al R18) - one ESF Train Fall 2016 refueling outage (i.e., Al R1 9) - remaining ESF Train Spring 2014 refueling outage (i.e., A2R17) - one ESF Train Fall 2015 refueling outage (i.e., A2R18) - remaining ESF Train Spring 2014 refueling outage (i.e., B1 R19) -one ESF Train Fall 2015 refueling outage (i.e., B1R20) - remaining ESF Train Fall 2014 refueling outage (i.e., B2R18) - one ESF Train Spring 2016 refueling outage (i.e., B2R19) - remaining ESF Train As shown, the associated hardware will be installed over two outages for each unit; however, the trip capability will be activated following NRC approval on the following projected schedule:

Braidwood Unit 1:

Braidwood Unit 2:

Byron Unit 1:

Byron Unit 2:

Prior to MODE 4 following the Fall 2016 refueling outage (i.e., Al R19)

Prior to MODE 4 following the Fall 2015 refueling outage (i.e., A2R18)

Prior to MODE 4 following the Fall 2015 refueling outage (i.e., B1R20)

Prior to MODE 4 following the Spring 2016 refueling outage (i.e., B2R19) 3 of 21

ATTACHMENT I Evaluation of Proposed Changes 2.0 DETAILED DESCRIPTION The proposed changes involve revising Technical Specifications (TS) 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation." Specifically, LCO 3.3.5 would be revised to include a new "low degraded voltage" Function; and the associated Surveillance Requirement (SR) 3.3.5.2 would also be revised accordingly to perform a CHANNEL CALIBRATION to verify the specified values for the new low degraded voltage Allowable Value and time delay setting.

The detailed justification for these changes and associated values is presented below in Section 3.0, "Technical Evaluation."

TS 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation" The current LCO 3.3.5 states the following:

LCO 3.3.5 Two channels per bus of the loss of voltage Function and two channels per bus of the degraded voltage Function shall be OPERABLE.

The proposed change would revise this LCO to include a new low degraded voltage Function as follows:

LCO 3.3.5 Two channels per bus of the loss of voltage Function, two channels per bus of the degraded voltage Function and two channels per bus of the low degraded voltage Function shall be OPERABLE.

SR 3.3.5.2 (CHANNEL CALIBRATION)

The current SR 3.3.5.2 states the following:

SR 3.3.5.2 Perform CHANNEL CALIBRATION with setpoint Allowable Value as follows:

a. Loss of voltage Allowable Value > 2730 V with a time delay of s 1.9 seconds.

b. Degraded voltage Allowable Value 2 [3930 V-Braidwood; 3793 V-Byron]

with a time delay of 310 +/- 30 seconds.

The proposed change would revise this SR to include a new Allowable Value and time delay for the low degraded voltage Function as follows:

SR 3.3.5.2 Perform CHANNEL CALIBRATION with setpoint Allowable Value as follows:

a. Loss of voltage Allowable Value >- 2730 V with a time delay of 5 1.9 seconds.

b. Degraded voltage Allowable Value > [3930 V-Braidwood; 3793 V-Byron]

with a time delay of 310 +/- 30 seconds.

c. Low degraded voltage Allowable Value 2 [3059 V-Braidwood; 3075 V-Byron] with a time delay of 5 3.5 seconds.

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ATTACHMENT I Evaluation of Proposed Changes Note that the associated setpoints for the proposed TS Allowable Values for the new low degraded voltage Function will be specified in the Technical Requirement Manual (TRM),

Table T2.0.b-1, "Engineered Safety Feature Actuation System Instrumentation Trip Setpoints."

The setpoint values will be more conservative than the TS Allowable Values and will be set at 75% of nominal bus voltage; i.e., 3120 V. A summary table showing the TS Allowable Values and associated TRM nominal setpoints is provided below.

Table 2-1 TS Allowable Values (AV) and TRM Setpoints (SP)

Braidwood Byrn TS AV - Loss of Voltage

->2730V (65.6%)

>2730V (65.6%)

w/:51.9 sec time delay w/51.9 sec time delay TRM SP - Loss of Voltage 2>2870V (69.0%)

-2870V (69.0%)

w/ 51.8 sec time delay w/< 1.8 sec time delay TS AV - Degraded Voltage

>3930V (94.5%)

Ž3793V (91.2%)

w/ 310+/-30 sec time delay w/ 310+/-30 sec time delay TRM SP - Degraded Voltage

>3987V (95.8%)

>3847V (92.5%)

w/ 310 sec time delay w/ 310 sec time delay TS AV - Low Degraded Voltage

-3059V (73.5%)

2!3075V (73.9%)

(proposed) w/!53.5 sec time delay w/53.5 sec time delay TRM SP - Low Degraded Voltage

Ž3120V (75.0%)

>3120V (75.0%)

(proposed) w/ 3.0 sec time delay w/ 3.0 sec time delay NOTE: Percentages are given as percent of the nominal bus voltage of 4160 volts The marked-up TS pages showing the proposed changes are provided in Attachment 2A and 2B for Braidwood Station and Byron Station respectively.

Note that the revised associated TS Bases pages are included, for information only, in Attachments 3A and 3B for Braidwood Station and Byron Station respectively.

Appropriate revisions to the Updated Final Safety Analysis Report and TRM will also be completed after approval of these proposed changes.

3.0 TECHNICAL EVALUATION

3.1 Overview and Background 3.1.1 ESF Bus Undervoltage Protection Function The Emergency Diesel Generators (EDGs) provide a source of emergency power when offsite power is either unavailable or is insufficiently stable to allow safe unit operation. Undervoltage protection circuitry will generate an LOP EDG start signal and disconnect the ESF buses from the offsite power supply if a loss of voltage or degraded voltage condition occurs on the 4.16 kV ESF bus. Subsequently, the EDG output breaker will close and power the ESF buses. This undervoltage protection circuitry consists of the first-level loss of voltage protection and the 5 of 21

ATTACHMENT 1 Evaluation of Proposed Changes second-level degraded voltage protection. Each 4.16 kV ESF bus has an independent LOP EDG start signal.

Currently, two undervoltage relays with inverse time characteristics are provided on each 4.16 kV ESF bus for detecting a loss of bus voltage condition. Two degraded voltage relays with definite time characteristics are also provided on each 4.16 kV ESF bus for detecting a sustained degraded voltage condition. The undervoltage relays are combined in a two-out-of-two logic to generate an LOP signal if the voltage is below a nominal setpoint of 70% for a short time delay (i.e., 1.8 seconds) for the first-level undervoltage condition (i.e., loss of voltage condition). In a similar manner, the two degraded voltage relays are also combined in a two-out-of-two logic to generate an LOP signal if the voltage is below a nominal setpoint of 95.8%

for Braidwood Station (92.5% for Byron Station) for a long time (i.e., 310 seconds) for the second-level undervoltage condition (i.e., degraded voltage condition). These undervoltage functions are addressed in TS 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation," including surveillance requirements with relay Allowable Values and associated time delays. In TS 3.3.5, (for both Braidwood and Byron Stations) the minimum Allowable Value for the loss of voltage relays is > 2730 volts (i.e., > approximately 66%) with a time delay of < 1.9 seconds. Also in TS 3.3.5, for Braidwood Station, the minimum Allowable Value for the degraded voltage relays is > 3930 volts (i.e., > approximately 94.5%)

with a time delay of 310 + 30 seconds. For Byron Station, the minimum Allowable Value for the degraded voltage relays is > 3793 volts (i.e., > approximately 91.2%) with a time delay of 310 + 30 seconds. The relays are conservatively set at nominal setpoints greater than the minimum Allowable Values to account for relay tolerances. The existing nominal setpoint values are specified in TRM Table T2.0.b-1.

3.1.2 Chronology May 11, 2009 - Byron Station Unresolved Item During an NRC Component Design Bases Inspection (CDBI) at Byron Station in 2009 documented in Reference 3, an unresolved item (URI) was identified related to the design bases for the 4.16 kV ESF buses second level degraded voltage timer settings. The item was associated with the consequences of operating and/or starting safety-related equipment at a voltage as low as 75 percent of the 4.16 kV nominal bus voltage (i.e., above the loss of voltage relay setpoint) for as long as 5 minutes and 40 seconds (i.e., the maximum time delay value allowed in the TS SR) during a degraded grid voltage condition without a Loss of Coolant Accident (LOCA); (i.e., with no Safety Injection (SI) signal present). Note that under LOCA conditions (i.e., SI signal is present), the 5-minute time delay is bypassed and, after an initial 10-second time delay, the offsite power feeder breakers would trip and the EDGs would start and accept the safety-related loads according to the prescribed load sequence.

Byron Station did not have a specific analysis to demonstrate the ability of the safety-related loads to mitigate an event involving a degraded grid voltage condition (i.e., below 95.8% at Braidwood; 92.5% at Byron) when a LOCA (SI signal) was not present. If an SI signal was not present, after the 10-second delay, the degraded voltage condition resulted in an alarm in the control room and the start of the five-minute timer.

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ATTACHMENT I Evaluation of Proposed Changes Based on the direction in the Byron Station degraded voltage alarm response procedure, if the alarm was the result of a degraded voltage condition, operators were required to call the grid operator to determine whether the grid voltage could be increased and monitor the bus voltage.

Further, if the voltage dropped below 75%, the operators were directed to initiate a transfer of the loads to the EDGs by opening the System Auxiliary Transformer (SAT) feeder breakers (i.e., the normal supply breakers) to the 4.16kV ESF Buses (i.e., buses 141/241 and 142/242).

This action would cause the loss of voltage relays (LVRs) to pickup and automatically start the EDGs, which would then reenergize the ESF buses and automatically start the required safe shutdown equipment via the safeguards equipment load sequencers. Note that this commitment was made for Braidwood and Byron Stations in a letter from Cordell Reed (Commonwealth Edison (now Exelon Generation Company, LLC)), "Dresden Station Unit 2 and 3, 4kV Undervoltage Setpoint Meeting Action Items," dated April 21, 1989 (Reference 4).

The specific issue discussed in Reference 3 was that, if the voltage at the 4.16 kV bus dropped to slightly above 75 percent of the nominal voltage, the operating motors would experience approximately a 28 percent increase in current. If operated within the design limits and properly protected, these motors would most likely experience no major damage. However, during the subsequent intervening 5 minutes (due to the timer delay), the increase in motor load current could result in spurious breaker trips and the automatic restart of the same or redundant motors with subsequent further decrease in system voltages. At the lower voltage buses (i.e., 480V buses), the voltage drop would be greater than 25 percent due to losses in step-down transformers, cables, and other interposing devices. This voltage drop, complicated by potential motor starts, including the potential start of the motor-driven auxiliary feedwater pump if a plant trip occurred, could result in adverse consequences that had not been evaluated.

Byron Station wrote Issue Report (IR) No. 892610, "2009 CDBI Issue Degraded Voltage 5-Minute Timer," dated March 13, 2009 to address this issue. In the IR, Byron Station indicated that a technical basis addressing the 5-minute delay would be developed; however, in the interim, the appropriate alarm response procedures were revised to direct the operators to immediately separate the ESF buses from the SATs upon confirmation that a degraded bus voltage condition existed (i.e., below 92.5 percent at Byron Station).

At Braidwood Station, a parallel IR was written (i.e., IR 898238 dated March 26, 2009).

Braidwood performed an Operability Evaluation to confirm operability of the LOP DG Start Instrumentation. Subsequently, in response to a separate issue, alarm response procedures were revised to direct the operators to immediately separate the ESF buses from the SATs, upon confirmation that a degraded bus voltage condition existed (i.e., below 95.8 percent at Braidwood Station).

July 27, 2010 - Byron Station Non-cited Violation Byron Station performed an analysis to address the degraded voltage issue, documented in Engineering Change (EC) 377631, "Evaluation and Technical Basis for the AP System Second Level Undervoltage (Degraded Voltage) Time Delay Settings," dated February 3, 2010.

After reviewing EC 377631, it was concluded that the analysis did not adequately confirm the ability of the 4.16 kV ESF bus safety-related loads to continue to operate for 5 minutes and 40 seconds without sustaining damage during a worst case, non-accident degraded voltage 7 of 21

ATTACHMENT I Evaluation of Proposed Changes condition. Specifically, the current analysis only evaluated the operability of safety-related loads to a maximum degraded voltage of 75 percent of nominal. As previously noted, 75 percent of nominal voltage was chosen as the lower limit of the degraded voltage evaluation based on an operator manual action to separate the ESF buses from the offsite source, as directed by the alarm response procedures. This manual action had not been formally approved by the NRC.

Without the specified operator action, the voltage could drop to just above the first level undervoltage Allowable Value of approximately 66 percent of nominal bus voltage (i.e., the TS Allowable Value of 2730 V) during the 5 minute and 40 second time delay period. The analysis did not address operability of safety-related loads at that voltage level. The analysis also did not address whether non safety-related loads such as circulating water pumps would trip at the lowest possible degraded voltage causing a plant trip; and whether the safe shutdown loads, such as the motor driven auxiliary feedwater pump, would be able to start and perform their safety function.

Based on the NRC review, documented in Reference 1, a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion Ill, "Design Control," was issued for not having an appropriate analysis for the second level undervoltage (i.e., degraded voltage) relay timer settings.

November 2013 - Development of Engineering Changes to Resolve Issue Braidwood and Byron Stations continue to administratively address the non-conservative TS with alarm response procedures that direct operators to separate the ESF buses from the SATs, upon confirmation that a degraded bus voltage condition exists (i.e., below 92.5 percent for Byron; 95.8 percent for Braidwood) in accordance with NRC Administrative Letter 98-10 as noted above.

Engineering Change packages were subsequently developed for each unit at Braidwood Station and Byron Station to resolve the degraded voltage concern. The calculations supporting this modification (i.e., the addition of new relays and associated settings) are presented in Attachments 4 and 5 for Braidwood Units 1 and 2; and Byron Station Unit 1 and 2, respectively.

The results of these design basis calculations support the changes in this license amendment request and resolve the NRC concerns discussed in References 1 and 3 on a permanent basis.

3.2

System Description

The following current system description is provided to enhance understanding of the ESF electrical system and the proposed modification to address the degraded voltage issue. The below discussion is applicable to both Braidwood and Byron Stations and represents the current system configuration. Refer to Figure 1 (for Braidwood Station) and Figure 2 (for Byron Station) throughout this discussion. Note that these figures are used for training purposes and are presented here for information only. These figures are not controlled as design documents.

The designs of the onsite and offsite electric power systems are in compliance with General Design Criteria 17, "Electrical Power Systems," and 18, "Inspection and testing of electric power systems."

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ATTACHMENT 1 Evaluation of Proposed Changes Each unit has the required onsite power systems with sufficient independence, redundancy, and testability to ensure performance of their safety functions assuming a single failure. Two physically and electrically independent power distribution systems per unit, i.e., ESF divisions, are each fed by a standby EDG upon a loss of offsite power. The EDGs have been sized to meet the maximum expected horsepower requirements during a design-basis accident. Each ESF division is also served by a separate 125-Vdc battery source to provide power to safety-related d-c loads and control circuits.

Two physically independent offsite power sources serve each ESF distribution system as required by General Design Criterion 17. The first offsite source (unit SAT) serves as the normal feed to an ESF division, while the second offsite source (i.e., the other unit's SAT) can be made available manually by operator action.

The arrangement of the station auxiliary power systems provides for complete electrical isolation and physical separation of each unit's redundant power supplies and distribution system required for safety-related loads. Each separate power source (i.e., EDG and offsite source) is physically and electrically independent up to the point of connection to the 4.16 kV ESF buses, except when cross-tie links are installed. Redundant loads important to plant safety are split between ESF divisions as can be seen on Figures 1 and 2. These redundant loads are physically separated to maintain independence and to minimize the possibility of a common mode failure. All Class 1 E equipment is located in Seismic Category I structures. The ESF electrical systems are designed in accordance with IEEE Standards 279-1971, "Criteria for Protection Systems for Nuclear Power Stations," and 308-1974, "IEEE Standard Criteria for Class 1 E Power Systems for Nuclear Power Generating Stations."

There are two redundant and independent 4-kV emergency buses and, currently, each has two levels of undervoltage protection: 1) loss of power, and 2) degraded grid voltage. The relays are connected to the existing potential transformers on the bus. The first level of undervoltage protection is provided by induction disk type undervoltage relays. The second level of undervoltage protection is provided by instantaneous undervoltage relays with delayed drop-out.

The voltage and time setpoints are determined from an analysis of the voltage requirements of the safety-related loads and actual field measurements of bus voltages under various motor starting conditions. The approximate pickup voltage for the first level of protection is 70% of rated voltage. The setting for the second level of undervoltage protection is 92.5% of rated voltage (i.e., 3847 volts) at Byron Station and 95.8% (i.e., 3987 V) at Braidwood Station. There is a 10-second time delay to avoid alarms on transients, and if the degraded voltage is not corrected, the bus automatically disconnects from the offsite power source 5 minutes after the alarm and connects to its onsite EDG. During a sustained degraded grid voltage condition, the subsequent occurrence of an SI signal (due to a LOCA) immediately trips the offsite power supply to the 4-kV ESF buses.

The above setpoint is based on the maximum positive and negative tolerances of the relay and a minimum voltage of 90% at the terminals of Class 1 E motors.

The standby a-c power source (i.e., EDG) is completely independent of any auxiliary transformer sources of supply in the performance of its required function. It is capable of supplying power to the unit's electrical loads which are necessary for safe shutdown in the event 9 of 21

ATTACHMENT 1 Evaluation of Proposed Changes of a design-basis accident (i.e., LOCA). Due to the redundancy of the unit's ESF division and EDGs, the loss of any one of the EDGs will not prevent the safe shutdown of the unit. The total standby a-c power system, including EDGs and distribution equipment, satisfies single-failure criteria.

3.3 Proposed Modification and Technical Justification A number of options were evaluated to resolve the identified degraded voltage concern.

Braidwood and Byron Stations have decided to add new low degraded voltage relays (LDVRs) that would automate the previous manual action to open the SAT feed breakers to the ESF buses if the ESF bus voltage were to decrease to less than a nominal 3120 V (i.e., 75% of bus voltage) after a nominal 3 second time delay. Note that the design analysis evaluated the voltage levels and time delays down to the TS Allowable Values noted in Section 2.0 above.

The existing loss of voltage relays (LVRs) (i.e., the first level loss of voltage protection); and degraded voltage relays (DVRs) (i.e., the second-level degraded voltage protection) will remain in place with no changes to the Allowable Values or time delays.

Introducing this new low degraded voltage function (i.e., a third level of undervoltage protection) with definite time relay at an appropriately higher voltage than the LVR setpoint, will ensure the bus will trip prior to safety-related motors stalling or incurring damage as discussed in Attachments 4 and 5. By leaving the existing LVRs at the current setpoint, the bus continues to be protected against a complete grid voltage collapse by the existing inverse-time LVRs. The existing DVRs will continue to perform their function allowing time for voltage to recover for normal plant events (e.g., bus voltage transients due to large motor starts) with a definite time delay of 10 seconds at the existing higher degraded voltage setpoint (i.e., 95.8% of bus voltage for Braidwood; 92.5% of bus voltage for Byron). This option was selected to best address the degraded voltage time delay issue and is being implemented by subject ECs for each unit.

Specifically, the planned modifications will install new relays and timers to detect, alarm and trip on a low degraded voltage condition on the 4 kV engineered safety feature (ESF) buses 141/241 and 142/242. The new LDVR scheme will consist of two undervoltage relays and one timer for each bus. The new relays will be electrically connected to the 4kV ESF bus potential transformers (PT) at the switchgear cubicle. The new relays and timers will isolate the ESF buses when the bus voltage reaches 75% of rated voltage. As noted above, the LDVR protection represents the third level of undervoltage protection for the ESF buses and will be in addition to the existing two levels of undervoltage protection. Note that the new relay scheme trip function will be isolated via test switches until this LAR is approved. After LAR approval, the new relay scheme trip function will be enabled.

When a low degraded voltage condition is detected, both relays will actuate, after a short time delay of approximately 0.5 seconds, to energize the new timer. The relays actuate in a 2-out-of-2 logic, such that both relays have to actuate to initiate the degraded voltage alarm and the undervoltage sequence. The new timer will, after approximately 2.5 seconds after the relay actuates, close a contact that will cause the following to occur:

Open the SAT feed breaker to the 4kV ESF bus (preferred off-site power supply)

Open the tie breaker between the 4KV ESF bus and the associated 4kV non-ESF bus

" Open the tie breaker to the opposite unit 4kV ESF bus (alternate off-site power supply) 10 of 21

ATTACHMENT I Evaluation of Proposed Changes Note that the overall effective time delay setting for the LDVR function is 3.0 seconds (i.e.,

0.5 seconds for the LDVR relays plus 2.5 seconds for the new timer). To provide margin, the analyses were performed using a maximum Allowable Value of 3.5 seconds for the time delay which is the proposed TS Allowable Value.

With these breakers open, the bus is isolated from all sources other than the EDG and will be at zero volts. This condition will activate the existing low voltage relay system to initiate the start of the EDG and sequence the safety-related loads onto the bus powered by the EDG. In this way, the safety-related loads are protected from the effects of a degraded voltage condition.

Compliance with NUREG-0800, BTP PSB-1 The Braidwood Station and Byron Station design and licensing basis requirements for the degraded voltage logic are established in the NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Chapter 8, "Electric Power,"

Appendix 8-A, Branch Technical Position (BTP) PSB-1, "Adequacy of Station Electric Distribution System Voltages," Revision 0 (July 1981). Section B.1.b of BTP PSB-1 specifies that two separate time delays shall be selected for the second level of undervoltage protection based on the following conditions:

1. The first time delay should be of a duration that established the existence of a sustained degraded voltage condition (i.e., something longer than a motor starting transient). Following this delay, an alarm in the control room should alert the operator to the degraded condition.

The subsequent occurrence of a safety injection actuation signal (SIAS) should immediately separate the Class 1 E distribution system from the offsite power system.

2. The second time delay should be of a limited duration such that the permanently connected Class 1 E loads will not be damaged. Following this delay, if the operator has failed to restore adequate voltages, the Class 1 E distribution system should be automatically separated from the offsite power system. Bases and justification must be provided in support of the actual delay chosen.

In compliance with this requirement, the first time delay for the existing degraded voltage protection system (i.e., second-level) was established as 10 seconds and the second time delay was established as 300 seconds +/- 30 seconds. The total time delay value is specified in TS 3.3.5 as an Allowable Value of 310 seconds +/- 30 seconds at voltages as low as a nominal 66% of rated voltage (i.e., the TS minimum Allowable Value for the Loss of Voltage Relays of 2730 V).

As a result of the calculations and evaluations performed to justify the second time delay value, it was decided to install a LDVR system that will activate the existing low voltage system to isolate the ESF bus from the off-site power source when bus voltage drops below a nominal 75% rated voltage for longer than 3.0 seconds. Note that the corresponding TS 3.3.5 Allowable Values for the new LDVRs will be a bus voltage of > 73.5% rated voltage with a time delay of

-< 3.5 seconds (for Braidwood Station); and > 73.9% rated voltage with a time delay of

-< 3.5 seconds (for Byron Station). This system will be installed in parallel with the existing undervoltage relay systems and will not alter their function. The associated hardware will be installed in accordance with 10 CFR 50.59; however, as previously noted, the new LDVR 11 of 21

ATTACHMENT I Evaluation of Proposed Changes system trip functions will not be activated prior to approval and implementation of the LAR. The exception to this will be that the alarm function can be activated prior to approval of the LAR.

As the 4.16 kV switchgear for buses 141/142 and 241/242 are classified as Class 1E Safety Related and Seismic Category 1, this modification (for all four units) is also classified as Class 1 E Safety Related and the new voltage relays and time delay relays will be seismically qualified and mounted.

Failure Modes and Effects Review The new low degraded voltage protective relay scheme monitors the bus voltage on the 4.16kV ESF Switchgear 141/241 and 142/242 to verify bus voltage is high enough for the running safety related motors to continue to operate. Upon responding to a low voltage condition, the new protective relay scheme will actuate (after a nominal 3.0 second time delay) to pick-up the associated auxiliary relay which trips the associated 4.16kV Unit SAT feed, Unit non-safety bus crosstie, and opposite unit crosstie breakers to disconnect the buses from the affected electrical source.

Should one of the new low degraded voltage relays fail to operate, the existing degraded voltage protection scheme provided by the DVRs and LVRs would still be available and unaffected to provide the existing level of protection for the safety-related equipment. If one of the new low degraded voltage relays were to spuriously actuate, the relay on the same 4.16kV bus on the other phase (OAB or OBC) would not actuate and the 2 out of 2 logic would not be satisfied; therefore, the relay that disconnects the 4.16kV bus from the preferred power source would remain de-energized as it is only energized on 2 out of 2 logic scheme. The same conclusion is true if one of the two relays fails to reset due to the 2 out of 2 logic.

Should one of the new time delays fail to operate during a degraded voltage condition, the existing degraded undervoltage protection scheme is still available and unaffected to provide the existing level of protection for the safety-related equipment. Additionally, if the time delay relay for a bus fails to reset following a degraded voltage condition when the bus is connected to the EDG, the bus would not be able to reconnect to the normal SAT feed, the non-safety bus crosstie, or the opposite unit crosstie feed because the trip signal to those circuit breakers would remain sealed in. In this case, as with all of the possible failure modes, there are redundant safety trains and the opposite safety train would still be available to provide safe shutdown capability. This change to add new low degraded voltage protection functionally maintains all the existing interlock functions for the 4.16kV ESF switchgear relays.

The new LDVRs will, upon actuation, energize an auxiliary relay that initiates the trip of the ESF bus feeder breakers. This modification will not affect the number of occurrences of degraded voltage conditions that would cause the actuation of both the existing DVRs and the new LVDRs. Since this EC will simply implement a change to initiate the actuation of the relay scheme to isolate the ESF buses sooner than the existing degraded voltage protection scheme, there will be no increase in the failure rate of the auxiliary relay that trips the ESF bus feeder breakers. In addition, the auxiliary relay is subject to routine surveillance testing and maintenance to ensure it is capable of performing its intended function. Therefore, the addition of the new LDVRs does not cause an increase in the failure rate of the subject auxiliary relay.

12 of 21

ATTACHMENT I Evaluation of Proposed Changes LDVR Setpoint and Time Delay Calculations The calculations determining the LDVR setpoints and time delay values associated with this modification are presented in Attachments 4 and 5 for Braidwood Units 1 and 2; and Byron Station Unit I and 2, respectively. The setpoints and time delay values were developed in accordance with the EGC setpoint methodology. The associated modifications remain in compliance with the requirements of BTP PSB-I.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria The proposed change has been evaluated to determine whether the applicable regulations and requirements, noted below, continue to be met.

General Design Criterion 5, "Sharing of structures, systems, and components," states that no safety-related systems, structures, or components are shared unless such sharing has been evaluated to ensure that there will be no significant adverse impact on safety functions.

General Design Criterion 17, "Electric power systems," states that provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies.

Regulatory Guide 1.81, Revision 1, "Shared Emergency and Shutdown Electric Systems for Multi-Unit Nuclear Power Plants," states that, because of the low probability of a major reactor accident, a suitable design basis for multi-unit nuclear power plants is the assumption that an accident occurs in only one unit at a time, with all remaining units proceeding to an orderly shutdown and a maintained cooldown condition.

NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Chapter 8, "Electric Power," Appendix 8-A, Branch Technical Position (BTP)

PSB-1, "Adequacy of Station Electric Distribution System Voltages," Revision 0 (July 1981),

states, in part, as follows:

The technical specifications shall include limiting conditions for operations, surveillance requirements, trip setpoints with minimum and maximum limits, and allowable values for the second-level voltage protection sensors and associated time delay devices.

Based on the review of the above requirements, EGC has determined that the proposed change does not require any exemptions or relief from regulatory requirements, other than revising the TS as described, and does not affect conformance with any of the above noted regulatory requirements or criteria.

13 of 21

ATTACHMENT I Evaluation of Proposed Changes 4.2 No Significant Hazards Consideration In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit or early site permit," Exelon Generation Company, LLC, (EGC) requests amendments to Facility Operating License Nos. NPF-72 and NPF-77 for Braidwood Station, Units 1 and 2, and Facility Operating License Nos. NPF-37 and NPF-66 for Byron Station, Units I and 2. This amendment request proposes to revise Technical Specifications (TS) 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation." Specifically, LCO 3.3.5 would be revised to add a new "low degraded voltage" Function; and the associated Surveillance Requirement (SR) 3.3.5.2 would also be revised to add a CHANNEL CALIBRATION to verify the specified values for the new low degraded voltage Allowable Value and time delay setting.

As documented in a letter from R. A. Skokowski (NRC) to M. J. Pacilio (Exelon Generation Company, LLC), "Byron Station, Units 1 and 2, Integrated Inspection Report 05000454/2010003; 05000455/2010003," dated July 27, 2010 (Reference 1), Byron Station received a Green Finding with associated Non-cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion Ill, "Design Control," for not having an appropriate analysis for the second level undervoltage (i.e., degraded voltage) relay timer setting, currently specified in SR 3.3.5.2, Item b. Specifically, Byron Station's analysis did not adequately demonstrate the ability of the 4.16 kV ESF bus safety-related loads to continue to operate for 5 minutes and 40 seconds (i.e.,

the degraded voltage time delay period prior to being isolated from the normal off-site power source) without sustaining damage during a worst case, non-accident degraded voltage condition. Consequently, TS 3.3.5 is considered to be a non-conservative TS. This concern is also applicable to Braidwood Station.

It has been determined that a modification will be installed to resolve this concern. This modification will add new "low degraded voltage relays" (LDVRs) and timers (i.e., a third level of undervoltage protection), with appropriate settings, on each ESF bus. The addition of the LDVRs will continue to allow the existing undervoltage protection circuitry to function as originally designed; i.e., the first-level "loss of voltage" protection and the second-level "degraded voltage" protection will remain in place and be unaffected by this change. These new relays and timers will ensure the safety-related loads will not be damaged by appropriately isolating the safety-related loads (at 75% of nominal ESF bus voltage) from the normal off-site power source during a sustained degraded bus voltage event under non-accident conditions.

The safety-related loads will then be re-sequenced back on to the 4.16 kV EFS buses as designed, powered by the Emergency Diesel Generators (EDGs), and will continue to perform their design basis function.

Compliance with the intent of TS 3.3.5 is currently administratively controlled under the provisions of NRC Administrative Letter (AL) 98-10, "Dispositioning of Technical Specifications that are Insufficient to Assure Plant Safety," to assure that plant safety is maintained at both Braidwood and Byron Stations. This license amendment request is submitted in accordance with the guidance in AL 98-10.

14 of 21

ATTACHMENT I Evaluation of Proposed Changes According to 10 CFR 50.92, "Issuance of amendment," paragraph (c), a proposed amendment to an operating license involves no significant hazards consideration if operation of the facility in accordance with the proposed amendment would not:

(1)

Involve a significant increase in the probability or consequences of an accident previously evaluated; or (2)

Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3)

Involve a significant reduction in a margin of safety.

EGC has evaluated the proposed change for Braidwood Station and Byron Station, using the criteria in 10 CFR 50.92, and has determined that the proposed change does not involve a significant hazards consideration. The following information is provided to support a finding of no significant hazards consideration.

Criteria

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change to add new "low degraded voltage relays" (LDVRs) and associated CHANNEL CALIBRATION surveillance test provides a third level of undervoltage protection for the Engineered Safeguards Features (ESF) electrical buses. These new relays will further ensure that the normally operating safety-related motors/equipment, which are powered from the ESF buses, are appropriately isolated from the normal off-site power source and will not be damaged in the event of sustained degraded bus voltage. The addition of the LDVRs will continue to allow the existing undervoltage protection circuitry to function as originally designed; i.e., the first-level "loss of voltage" protection and the second-level "degraded voltage" protection will remain in place and be unaffected by this change. The proposed change does not affect the probability of any accident resulting in a loss of voltage or degraded voltage condition on the ESF electrical buses; and will positively impact the consequences of accidents previously evaluated as this change further ensures continued operation of safety-related equipment throughout the accident scenarios.

Specific analysis was performed and determined that the proposed LDVRs, with the specified allowable values and time delay, will ensure that the 4.16 kV ESF buses will be isolated from the normal off-site power source, at the appropriate voltage level, under non-accident sustained degraded voltage conditions. The normally operating safety related motors will be subsequently sequenced back on to the 4.16 kV ESF buses powered by the EDGs; and therefore, will not be damaged in the event of sustained degraded bus voltage during the time delay period prior to initiation of the first level loss of voltage trip function.

Therefore, these safety-related loads will be available to perform their design basis function should a loss-of-coolant accident (LOCA) occur concurrent with a loss-of-offsite power (LOOP) following the degraded voltage condition. The loading sequence (i.e., timing) of 15 of 21

ATTACHMENT 1 Evaluation of Proposed Changes safety-related equipment back onto the ESF bus, powered by the EDG, is not affected by the addition of the new LDVRs.

The addition of new LDVRs will have no impact on accident initiators or precursors; does not alter the accident analysis assumptions or the manner in which the plant is operated or maintained; and does not affect the probability of operator error.

Based on the above, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed change involves the addition of new "low degraded voltage relays" (LDVRs);

i.e., a third level of undervoltage protection for the ESF electrical buses, and adds an associated CHANNEL CALIBRATION surveillance test. This change helps ensure that the assumptions in the previously evaluated accidents, which may involve a degraded voltage condition, continue to be valid.

The proposed changes do not result in the creation of any new accident precursors; do not result in changes to any existing accident scenarios; and do not introduce any operational changes or mechanisms that would create the possibility of a new or different kind of accident. A specific failure mode and effects review was completed for the new LDVRs, considering their potential failure, and concluded that the addition of these relays would not affect the existing "loss of voltage" and "degraded voltage" protection schemes; would not affect the number of occurrences of degraded voltage conditions that would cause the actuation of the existing Loss of Voltage Relays (LVRs), Degraded Voltage Relays (DVRs) or new LVDRs; would not affect the failure rate of the existing protection relays; and would not impact the assumptions in any existing accident scenario.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

The current "loss of voltage" and "degraded voltage" protection circuitry is designed to appropriately isolate the normally operating safety-related motors/equipment, which are powered from the ESF buses, from the normal off-site power source such that the subject equipment will not be damaged in the event of sustained degraded bus voltage. The loss of voltage relays (LVRs) isolate the ESF buses at a TS voltage value of approximately 66% of the nominal bus value after a short time delay (i.e., 1.9 seconds); while the degraded voltage relays (DVRs) isolate the ESF buses at a TS voltage value of 94.5% for Braidwood (91.2% for Byron Station) of the nominal bus voltage after a longer time delay of up to 5 minutes and 40 seconds (if no safety injection signal is present). After the ESF buses are 16 of 21

ATTACHMENT 1 Evaluation of Proposed Changes isolated from the offsite power supply, the normally operating safety related motors will be sequenced back on to the 4.16 kV EFS bus powered by the EDG; and continue to perform their design basis function to mitigate the consequences of an accident, with a specified margin of safety.

A concern exists that ESF motors/equipment may be damaged when operating and/or starting safety-related equipment when bus voltage drops to just above the loss of voltage relay setpoint for the duration of the 5 minutes and 40 second time delay. The new LDVRs are being added to resolve this concern. Analysis has been performed that shows the ESF equipment will not be damaged at 75% of bus voltage; therefore, the LDVR setpoint will be set at 75% of nominal ESF bus voltage. With the addition of this new third level of undervoltage protection, the capability of the ESF equipment will be assured; and thus the equipment will continue to perform its design basis function to mitigate the consequences of the previously analyzed accidents; and maintain the existing margin to safety currently assumed in the accident analyses.

An EDG start due to a safety injection signal (i.e., Loss of Coolant Accident) and the subsequent sequencing of ESF loads back on to the ESF buses, powered by the EDG, is not adversely affected by this change. If an actual loss of voltage condition occurs on the ESF buses, the loss of voltage time delays will continue to isolate the 4.16 kV ESF distribution system from the offsite power source prior to the EDG assuming the ESF loads.

The ESF loads will sequence back on to the bus in a specified order and time interval; again ensuring that the existing accident analysis assumptions remain valid and the existing margin to safety is unaffected.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, EGC concludes that the proposed amendments do not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

4.3 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the site licensing basis and Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

EGC has evaluated this proposed operating license amendment consistent with the criteria for identification of licensing and regulatory actions requiring environmental assessment in accordance with 10 CFR 51.21, "Criteria for and identification of licensing and regulatory actions requiring environmental assessments." EGC has determined that these proposed changes to add a new third level of "low degraded voltage" protection to the Engineered Safety Features 17 of 21

ATTACHMENT I Evaluation of Proposed Changes (ESF) electrical buses, meet the criteria for a categorical exclusion set forth in paragraph (c)(9) of 10 CFR 51.22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," and as such, has determined that no irreversible consequences exist in accordance with paragraph (b) of 10 CFR 50.92, "Issuance of amendment." This determination is based on the fact that these changes are being proposed as an amendment to the license issued pursuant to 10 CFR 50, "Domestic Licensing of Production and Utilization Facilities," which changes a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, "Standards for Protection Against Radiation," or which changes an inspection or a surveillance requirement, and the amendment meets the following specific criteria:

(i)

The amendment involves no significant hazards consideration.

As demonstrated in Section 4.2, "No Significant Hazards Consideration," the proposed change does not involve any significant hazards consideration.

(ii)

There is no significant change in the types or significant increase in the amounts of any effluent that may be released offsite.

The proposed change does not result in an increase in power level, does not increase the production nor alter the flow path or method of disposal of radioactive waste or byproducts. It is expected that all plant equipment would operate as designed in the event of an accident to minimize the potential for any leakage of radioactive effluents.

The proposed changes will have no impact on the amounts of radiological effluents released offsite during normal at-power operations or during the accident scenarios.

Based on the above evaluation, the proposed change will not result in a significant change in the types or significant increase in the amounts of any effluent released offsite.

(iii)

There is no significant increase in individual or cumulative occupational radiation exposure.

There is no change in individual or cumulative occupational radiation exposure due to the proposed change. Specifically, the change to add new third level of "low degraded voltage" protection to the ESF electrical buses has no impact on any radiation monitoring system setpoints. The proposed action will not change the level of controls or methodology used for processing of radioactive effluents or handling of solid radioactive waste, nor will the proposed action result in any change in the normal radiation levels within the plant.

Therefore, in accordance with 10 CFR 51.22, paragraph (b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

18 of 21

ATTACHMENT I Evaluation of Proposed Changes

6.0 REFERENCES

1. Letter from R. A. Skokowski (NRC) to M. J. Pacilio (Exelon Generation Company, LLC),

"Byron Station, Units 1 and 2, Integrated Inspection Report 05000454/2010003; 05000455/2010003," July 27, 2010

2. NRC Administrative Letter 98-10, "Dispositioning of Technical Specifications that are Insufficient to Assure Plant Safety," December 29, 1998

3. Letter from A. M. Stone (NRC) to C. G. Pardee (Exelon Generation Company, LLC), "Byron Station, Units 1 and 2, NRC Component Design Bases Inspection (CDBI) Inspection Report 05000454/2009007 (DRS); 05000455/2009007 (DRS)," May 11, 2009

4. Letter from Cordell Reed (Commonwealth Edison (now Exelon Generation Company, LLC)),

"Dresden Station Unit 2 and 3, 4kV Undervoltage Setpoint Meeting Action Items,"

April 21, 1989 19 of 21

YARD 1E MFT'Ar I'WW PT 345 W YARM T--3 At Power lineup:

Bus 141,142, 158, & 159 fed from SATs Bus 143,144,156, & 157 fed from UATs ESF Buses:

4160 volt ac Bus 141 & 142.

480 volt ac Bus 131 & 132 (both USS & MCC's) 125 volt dc Bus 111 & 112.

120 volt ac Inst Bus 111, 112,113, & 114.

UI BUS-5541-0 so 03U 133X 133Y

'I '1 CCIV MCC11 1333 '31 0N s5

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34v 134Z MC1 14Y 34Yvs 3 4

q13M1 34V A

V{)C

3

'VI Bus 131X T

T I I

2T UJM PZR HM$ PZR HM* g MU GOP-A OEt 03.0 FRO M=CC 1512 MCC033TIAMCC 03310 MCC 033T GAlE MTE GATE CSC b

13 1M3C11A I

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2 1-Bus Labeling Character / Represents 1st t Unit 2nd Voltage 3rd : Bus

Reference:

20E-1-4001A Bus Voltage Nomenclature 1 = 120 VAC or 125 VDC 3 =480VAC 4 =4160 VAC 5 = 6900 VAC AC-7, AC ONE LINE DIAGRAM I FEBRUARY 24, 2010, REV 7 FOR TRAINING USE ONLY Figure 1 - Braidwood Station Electrical Distribution System Page 20 of 21

IWr-

w6V iC I-Ia ACWA

.w wA AC-3, AC one line Diagram September 8, 2006, Rev. 25 Figure 2 - Byron Station Electrical Distribution System ForTrng Um Only Page 21 of 21 C 2006, EXELONCORP

ATTACHMENT 2A Markup of Technical Specifications Pages BRAIDWOOD STATION UNITS I AND 2 Docket Nos. 50-456 and 50-457 Facility Operating License Nos. NPF-72 and NPF-77 REVISED TS PAGES 3.3.5-1 3.3.5-2

LOP DG Start Instrumentation 3.3.5 3.3 INSTRUMENTATION 3.3.5 Loss of Power (LOP)

Diesel Generator (DG) Start Instrumentation LCO 3.3.5 Two channels per bus of the loss of voltage Function, @nd two channels per bus of the degraded voltage Functionand two channels per bus of the low degraded voltaae Function shall be OPERABLE.

MODES 1, 2, 3, and 4; When associated DG is required to be OPERABLE by LCO 3.8.2, "AC Sources-Shutdown."

APPLICABILITY:

ACTIONS NOTE-Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions A.1

NOTE------

with one channel on For loss of voltage one or more buses Function, the inoperable, inoperable channel may be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of the other channel.

Place channel in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months trip.

B. One or more Functions B.1 Restore one channel 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with two channels on for the Function on one or more buses the affected bus to inoperable.

OPERABLE status.

(continued)

BRAIDWOOD - UNITS 1 & 2 3.3.5 -

1 Amendment 49 1

LOP DG Start Instrumentation 3.3.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Enter applicable Immediately associated Completion Condition(s) and Time not met.

Required Action(s) for the associated DG made inoperable by LOP DG start instrumentation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.5.1 NOTE----------------

Verification of relay setpoints not required.

Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.2 Perform CHANNEL CALIBRATION with setpoint In accordance Allowable Value as follows:

with the Surveillance

a.

Loss of voltage Allowable Value Frequency 2730 V with a time delay of Control Program 1.9 seconds.

b.

Degraded voltage Allowable Value

> 3930 V with a time delay of 310 +/- 30 seconds.

c. Low dearaded voltaae Allowab e Value 23059 V with a time delay-of

<3.5 seconds.

BRAIDWOOD -

UNITS 1 & 2 3.3.5 - 2 Amendment 464466 1

ATTACHMENT 2B Markup of Technical Specifications Pages BYRON STATION UNITS 1 AND 2 Docket Nos. 50-454 and 50-455 Facility Operating License Nos. NPF-37 and NPF-66 REVISED TS PAGES 3.3.5-1 3.3.5-2

LOP DG Start Instrumentation 3.3.5 3.3 INSTRUMENTATION 3.3.5 Loss of Power (LOP)

Diesel Generator (DG)

Start Instrumentation LCO 3.3.5 Two channels per bus of the loss of voltage Function-, a4 two channels per bus of the degraded voltage Function an two channels per bus of the low degraded voltaae Function shall be OPERABLE.

MODES 1, 2, 3, and 4; When associated DG is required to be OPERABLE by LCO 3.8.2, "AC Sources-Shutdown."

APPLICABILITY:

ACTIONS NOTE-Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions A.1

NOTE------

with one channel on For loss of voltage one or more buses Function, the inoperable, inoperable channel may be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of the other channel.

Place channel in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months trip.

B. One or more Functions B.1 Restore one channel 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with two channels on for the Function on one or more buses the affected bus to inoperable.

OPERABLE status.

(continued)

BYRON -

UNITS 1 & 2 3.3.5 -

1 Amendment 4Q6 I

LOP DG Start Instrumentation 3.3.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Enter applicable Immediately associated Completion Condition(s) and Time not met.

Required Action(s) for the associated DG made inoperable by LOP DG start instrumentation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.5.1 NOTE---------------

Verification of relay setpoints not requi red.

Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.2 Perform CHANNEL CALIBRATION with setpoint In accordance Allowable Value as follows:

with the Surveillance

a.

Loss of voltage Allowable Value Frequency

> 2730 V with a time delay of Control Program

_< 1.9 seconds.

b.

Degraded voltage Allowable Value

_> 3793 V with a time delay of 310 +/- 30 seconds.

c.

Low dearded vol taae All owabl e Val ue

>_ 3075 V With a time delay of

_< 3.5 seconds.

BYRON -

UNITS 1 & 2 3.3.5 - 2 Amendment I

ATTACHMENT 3A Markup of Bases Pages BRAIDWOOD STATION UNITS 1 AND 2 Docket Nos. 50-454 and 50-455 Facility Operating License Nos. NPF-37 and NPF-66 REVISED BASES PAGES B3.3.5-1 B3.3.5-2 (no change - included for continuity)

B3.3.5-3 B3.3.5-4 B3.3.5-5 B3.3.5-6 (no change - included for continuity)

LOP DG Start Instrumentation B 3.3.5 B 3.3 INSTRUMENTATION B 3.3.5 Loss Of Power (LOP)

Diesel Generator (DG)

Start Instrumentation BASES BACKGROUND The DGs provide a source of emergency power when offsite power is either unavailable or is insufficiently stable to allow safe unit operation.

Undervoltage protection will generate an LOP start if a loss of voltagedegraded FD*

or voltage or low dearaded voltae condition occurs.

There are two LOP start signals, one for each 4.16 kV ESF bus.

Two undervoltage relays with inverse time characteristics are provided on each 4.16 kV ESF bus for detecting a.og of bus voltaae conditin.two dearade vola0 4eas withl deiie time c~haracteristics ace nrovided on each 4.16k LES bus for detectina a sustained degrde volta condition: and two low d araded voltage re ays with detfinte time characteristics are urovided on each 4-16 kV ESF bus tor deectina a low dearaaded voltaae condtio.

The undervoljtage relays are

-orip ia w

-ou -o-W The L Pstart ac tatio is e re n UFSAR,

ection 8.3 (Ref.

1).

Th priT Seti n i;

d-A-T T

eo Va-lue -S Allowable Values provide a conservative margin with regards to instrument uncertainties to ensure analytical limits are not violated during anticipated operational occurrences and that the consequences of Design Basis Accidents (DBAs) will be acceptable providing the unit is operated from within the LCOs at the onset of the event and required equipment functions as designed.

DA"Two undervoltage relays with inverse time characteristics are provided on each 4.16 kV ESF bus for detecting a sustained degraded voltage condition or a loss of bus voltage.

The relays are combined in a two-out-of-two logic to generate an LOP signal if the voltage is below 70% for a short time or below 95.8% for a long time.

The LOP start actuation is described in

UFSAR, Section 8.3 (Ref.

D1.A BRAIDWOOD - UNITS 1 & 2 B 3.3.5 - 1 Revision XX

LOP DG Start Instrumentation B 3.3.5 BASES BACKGROUND (continued)

Trip Setpoints are the nominal values at which the relays are set.

The actual nominal Trip Setpoint entered into the relay is more conservative than that specified by the Allowable Value to account for changes in random and non-random measurement errors.

One example of such a change in measurement error is attributable to calculated normal uncertainties during the surveillance interval.

Any relay is considered to be properly adjusted when the "as left" value is within the band for CHANNEL CALIBRATION tolerance.

If the measured value of a relay exceeds the Trip Setpoint but is within the Allowable Value, then the associated LOP DG Start Instrumentation function is considered OPERABLE.

Trip Setpoints are specified in Reference 2.

APPLICABLE The LOP DG start instrumentation is required for the SAFETY ANALYSES Engineered Safety Features (ESF) Systems to function in any accident with a loss of offsite power.

Its design basis is that of the Engineered Safety Feature Actuation System (ESFAS).

Accident analyses credit the loading of the DG based on the loss of offsite power during a Loss Of Coolant Accident (LOCA).

The actual DG start has historically been associated with the ESFAS actuation.

The DG loading has been included in the delay time associated with each safety system component requiring DG supplied power following a loss of offsite power.

The analyses assume a non-mechanistic DG loading, which does not explicitly account for each individual component of loss of power detection and subsequent actions.

The required channels of LOP DG start instrumentation, in conjunction with the ESF systems powered from the DGs, provide unit protection in the event of any of the analyzed accidents discussed in Reference 3, in which a loss of offsite power is assumed.

BRAIDWOOD -

UNITS 1 & 2 B 3.3.5 - 2 Revision 0

LOP DG Start Instrumentation B 3.3.5 BASES APPLICABLE SAFETY ANALYSES (continued)

The delay times assumed in the safety analysis for the ESF equipment include the DG start delay, and the appropriate sequencing delay, if applicable.

The response times for ESFAS actuated equipment in LCO 3.3.2, "Engineered Safety Feature Actuation System (ESFAS)

Instrumentation," include the appropriate DG loading and sequencing delay.

The LOP DG start instrumentation channels satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO for LOP DG start instrumentation requires that two channels (i.e.. two relavs) per bus of the loss of voltage o

,degraded voltage an low dearaded voltae unctinssall-e-k OPERALETnMDS 1, 2, 3, and 4 when the LOP DG start instrumentation supports safety systems associated with the ESFAS.

In MODES 5 and 6, the channels must be OPERABLE whenever the associated DG is required to be OPERABLE to ensure that the automatic start of the DG is available when needed.

Loss of the LOP DG Start Instrumentation Function could result in the delay of safety systems initiation when required.

This could lead to unacceptable consequences during accidents.

During the loss of offsite power, DG A powers the motor driven auxiliary feedwater pump.

Failure of this pump to start would leave only the diesel driven pump, as well as an increased potential for a loss of decay heat removal through the secondary system.

APPLICABILITY The LOP DG Start Instrumentation Functions are required in MODES 1, 2, 3, and 4 because ESF Functions are designed to provide protection in these MODES.

Actuation in MODE 5 or 6 is required whenever the required DG must be OPERABLE so that it can perform its function on an LOP or degraded power to the vital bus.

BRAIDWOOD - UNITS 1 & 2 B 3.3.5 - 3 Revision XX

LOP DG Start Instrumentation B 3.3.5 BASES ACTIONS In the event a channel's Trip Setpoint is found nonconservative with respect to the Allowable Value, or the channel is found inoperable, then the function that channel provides must be decl ared inoperable and the LCO Condition entered for the particular protection function affected.

A Note has been added in the ACTIONS to clarify the application of Completion Time rules.

The Conditions of this Specification may be entered separately for each Function listed in the LCO on a per bus basis.

The Completion Time(s) of the inoperable channel(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.

A.1 Condition A applies to the LOP DG Start Instrumentation Function with one channel on one or more buses inoperable.

If one channel is inoperable, Required Action A.1 requires that channel to be placed in trip within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

With a channel in trip, the LOP DG Start Instrumentation channels are configured to provide a one-out-of-one logic to initiate an undervoltage*_degraded voltage or low dearaded voltaae or signal for that bus.

For the Loss of Voltage Function, a Note is added to allow bypassing an inoperable channel for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of the other channel.

This allowance is made where bypassing the channel does not cause an actuation.

The specified Completion Time is reasonable considering the low probability of an event occurring during these intervals.

B.1 Condition B applies to eachothe LOP DG Start Instrumentation Function, with two channels on one or more buses inoperable.

Required Action B.1 requires restoring one channel of the affected Function to OPERABLE status.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time takes into account the low probability of an event requiring an LOP start occurring during this interval.

BRAIDWOOD -

UNITS 1 & 2 B 3.3.5 - 4 Revision XX BRAIDWOOD - UNITS 1 & 2 B 3.3.5 - 4 Revision XX

LOP DG Start Instrumentation B 3.3.5 BASES ACTIONS (continued)

C.1 Condition C applies to each of the LOP DG Start Instrumentation Functions when the Required Action and associated Completion Time for Condition A or B are not met.

In these circumstances the Conditions specified in LCO 3.8.1, "AC Sources-Operating," or LCO 3.8.2, "AC Sources-Shutdown," for the DG made inoperable by failure of the LOP DG start instrumentation are required to be entered immediately.

The actions of those LCOs provide for adequate compensatory actions to assure plant safety.

SURVEILLANCE SR 3.3.5.1 REQUIREMENTS SR 3.3.5.1 is the performance of a TADOT.

The test checks trip devices that provide actuation signals directly, bypassing the analog process control equipment.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note that excludes verification of relay setpoints during the TADOT.

SR 3.3.5.2 SR 3.3.5.2 is the performance of a CHANNEL CALIBRATION.

The setpoints, as well as the response to a loss of voltage,.

a degraded voltage and a low dearaded voltaoe test, shall include a single point verification that the trip occurs within the required time delay, as described in Reference 1.

CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Dddd and BRAIDWOOD - UNITS 1 & 2 B 3.3.5 - 5 Revision XX

LOP DG Start Instrumentation B 3.3.5 BASES REFERENCES

1.

UFSAR, Section 8.3.

2.

Technical Requirements Manual.

3.

UFSAR, Chapter 15.

BRAIDWOOD -

UNITS 1 & 2 B 3.3.5 -

6 Revision 0 BRAIDWOOD - UNITS 1 & 2 B 3.3.5 - 6 Revision 0

ATTACHMENT 3B Markup of Bases Pages BYRON STATION UNITS I AND 2 Docket Nos. 50-454 and 50-455 Facility Operating License Nos. NPF-37 and NPF-66 REVISED TS PAGES B3.3.5-1 B3.3.5-2 (no change - included for continuity)

B3.3.5-3 B3.3.5-4 B3.3.5-5 B3.3.5-6 (no change - included for continuity)

LOP DG Start Instrumentation B 3.3.5 B 3.3 INSTRUMENTATION B 3.3.5 Loss Of Power (LOP)

Diesel Generator (DG)

Start Instrumentation BASES BACKGROUND The DGs provide a source of emergency power when offsite power is either unavailable or is insufficiently stable to allow safe unit operation.

Undervoltage protection will generate an LOP start if a loss of voltage. degraded voltage or low degraded voltage condition occurs.

There are two LOP start signals, one for each 4.16 kV ESF bus.

Two undervoltage relays with inverse time characteristics are provided on each 4.16 kV ESF bus for detecting a of bus voltaae condition-two dearadedl vtace relavs with ddeinite timel characteristics are provide on each 4.16 kV ESF bus JOE detectinp a sustained dearaded voltage codtion: and two low dectrade v0ltaE relav Y.ith de~finite time_ characterijsticsj are Lrovided on each 4.1h kV

=Ddd-t or ESF bus for detecting a low dearaded voltaoe condition.

The undcervoltaae rel[av are combined in a two-out-of-two loaic to cienerate an WEP signal If the voltaae, j5 below a nominal setnoint of 70% for a sh=rt time delay tor the frtlevel undervltage condition ii.e.. I=s of voltaae condition).

The two dearaded voltage relavs are aUP o

Sn A two-oujt-f-twn Ioaic to aenerate an LOP sional it the voltaae is below a nominal setnoint of 92.5%

for a lo atime for the second-level undervo taae condition ie.. derraded voltae e crndly tian)r eicomarlnd itwol derddvoltage relavs are combined in a two-out-of-two loaic to aenerate an LOP sigana ifL te yoltaae iss pelow a nominal setuoint of Z5% for a hot time for theti rd level undervoltaae condition (i.e.. low dearaded voItage c

Qdt'n).

The LOP start actuation is described in UFSýAR, Section 8.3 (Ref. 1).

TrinI76f-5-6ints and AllowabTlVaTues Allowable Values provide a conservative margin with regards to instrument uncertainties to ensure analytical limits are not violated during anticipated operational occurrences and that the consequences of Design Basis Accidents (DBAs) will be acceptable providing the unit is operated from within the LCOs at the onset of the event and required equipment functions as designed.

Dddk Two undervoltage relays with inverse time characteristics are provided on each 4.16 kV ESF bus for detecting a sustained degraded voltage condition or a loss of bus voltage.

The relays are combined in a two-out-of-two logic to generate an LOP signal if the voltage is below 70% for a short time or below 92.5% for a long time.

The LOP start actuation is described in UFSAR, Section 8.3 (Ref.

1).1 BYRON - UNITS 1 & 2 B 3.3.5 - 1 Revision XX

LOP DG Start Instrumentation B 3.3.5 BASES BACKGROUND (continued)

Trip Setpoints are the nominal values at which the relays are set.

The actual nominal Trip Setpoint entered into the relay is more conservative than that specified by the Allowable Value to account for changes in random and non-random measurement errors.

One example of such a change in measurement error is attributable to calculated normal uncertainties during the surveillance interval.

Any relay is considered to be properly adjusted when the "as left" value is within the band for CHANNEL CALIBRATION tolerance.

If the measured value of a relay exceeds the Trip Setpoint but is within the Allowable Value, then the associated LOP DG Start Instrumentation function is considered OPERABLE.

Trip Setpoints are specified in Reference 2.

APPLICABLE The LOP DG start instrumentation is required for the SAFETY ANALYSES Engineered Safety Features (ESF) Systems to function in any accident with a loss of offsite power.

Its design basis is that of the Engineered Safety Feature Actuation System (ESFAS).

Accident analyses credit the loading of the DG based on the loss of offsite power during a Loss Of Coolant Accident (LOCA).

The actual DG start has historically been associated with the ESFAS actuation.

The DG loading has been included in the delay time associated with each safety system component requiring DG supplied power following a loss of offsite power.

The analyses assume a non-mechanistic DG loading, which does not explicitly account for each individual component of loss of power detection and subsequent actions.

The required channels of LOP DG start instrumentation, in conjunction with the ESF systems powered from the DGs, provide unit protection in the event of any of the analyzed accidents discussed in Reference 3, in which a loss of offsite power is assumed.

BYRON - UNITS 1 & 2 B 3.3.5 - 2 Revision 0

LOP DG Start Instrumentation B 3.3.5 BASES APPLICABLE SAFETY ANALYSES (continued)

The delay times assumed in the safety analysis for the ESF equipment include the DG start delay, and the appropriate sequencing delay, if applicable.

The response times for ESFAS actuated equipment in LCO 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation," include the appropriate DG loading and sequencing delay.

The LOP DG start instrumentation channels satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO for LOP DG start instrumentation requires that two channels (i.e.. two relays) per bus ofthe loss of voltage I

both degraded voltage and low dearaded voltaae Function-ssalle-*

i and OPERABLE in MODES 1, 2, 3, and 4 when the LOP DG start instrumentation supports safety systems associated with the ESFAS.

In MODES 5 and 6, the channels must be OPERABLE whenever the associated DG is required to be OPERABLE to ensure that the automatic start of the DG is available when needed.

Loss of the LOP DG Start Instrumentation Function could result in the delay of safety systems initiation when required.

This could lead to unacceptable consequences during accidents.

During the loss of offsite power, DG A powers the motor driven auxiliary feedwater pump.

Failure of this pump to start would leave only the diesel driven pump, as well as an increased potential for a loss of decay heat removal through the secondary system.

APPLICABILITY The LOP DG Start Instrumentation Functions are required in MODES 1, 2, 3, and 4 because ESF Functions are designed to provide protection in these MODES.

Actuation in MODE 5 or 6 is required whenever the required DG must be OPERABLE so that it can perform its function on an LOP or degraded power to the vital bus.

BYRON - UNITS 1 & 2 B 3.3.5 - 3 Revision XX

LOP DG Start Instrumentation B 3.3.5 BASES ACTIONS In the event a channel's Trip Setpoint is found nonconservative with respect to the Allowable Value, or the channel is found inoperable, then the function that channel provides must be declared inoperable and the LCO Condition entered for the particular protection function affected.

A Note has been added in the ACTIONS to clarify the application of Completion Time rules.

The Conditions of this Specification may be entered separately for each Function listed in the LCO on a per bus basis.

The Completion Time(s) of the inoperable channel(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.

A.1 Condition A applies to the LOP DG Start Instrumentation Function with one channel on one or more buses inoperable.

If one channel is inoperable, Required Action A.1 requires that channel to be placed in trip within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

With a channel in trip, the LOP DG Start Instrumentation channels are configured to provide a one-out-of-one logic to initiate an undervoltage*_ degraded yotaee sina or low daraded or vltaae for that bus.

For the Loss of Voltage Function, a Note is added to allow bypassing an inoperable channel for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of the other channel.

This allowance is made where bypassing the channel does not cause an actuation.

The specified Completion Time is reasonable considering the low probability of an event occurring during these intervals.

B.1 Condition B applies to e othe LOP DG Start Instrumentation Function, with two channels on one or more buses inoperable.

Required Action B.1 requires restoring one channel of the affected Function to OPERABLE status.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time takes into account the low probability of an event requiring an LOP start occurring during this interval.

BYRON - UNITS I & 2 B 3.3.5 - 4 Revision XX

LOP DG Start Instrumentation B 3.3.5 BASES ACTIONS (continued)

C.1 Condition C applies to each of the LOP DG Start Instrumentation Functions when the Required Action and associated Completion Time for Condition A or B are not met.

In these circumstances the Conditions specified in LCO 3.8.1, "AC Sources-Operating," or LCO 3.8.2, "AC Sources-Shutdown," for the DG made inoperable by failure of the LOP DG start instrumentation are required to be entered immediately.

The actions of those LCOs provide for adequate compensatory actions to assure plant safety.

SURVEILLANCE SR 3.3.5.1 REQUIREMENTS SR 3.3.5.1 is the performance of a TADOT.

The test checks trip devices that provide actuation signals directly, bypassing the analog process control equipment.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note that excludes verification of relay setpoints during the TADOT.

SR 3.3.5.2 SR 3.3.5.2 is the performance of a CHANNEL CALIBRATION.

The setpoints, as well as the response to a loss of voltage.,

a degraded voltage and a low deoraded yoltage test, shall include a single point verification that the trip occurs within the required time delay, as described in Reference 1.

CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

l and BYRON - UNITS 1 & 2 B 3.3.5 - 5 Revision XX

LOP DG Start Instrumentation B 3.3.5 BASES SURVEILLANCE REQUIREMENTS (continued)

The Frequency of 18 months is based on operating experience and consistency with the typical industry refueling cycle and is justified by the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

REFERENCES

1.

UFSAR, Section 8.3.

2.

Technical Requirements Manual.

3.

UFSAR, Chapter 15.

BYRON - UNITS 1 & 2 B 3.3.5 - 6 Revision 0

ML14120A039

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3.0 TECHNICAL EVALUATION

System Description

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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6.0 REFERENCES

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SUMMARY

3.0 TECHNICAL EVALUATION

System Description

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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3.0 TECHNICAL EVALUATION

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4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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