RS-14-337, Units 1 & 2 - License Amendment Request for Diesel Generator Load Rejection Surveillance Requirement

Units 1 & 2 - License Amendment Request for Diesel Generator Load Rejection Surveillance Requirement

ML14352A204
Person / Time
Site:	Byron, Braidwood
Issue date:	12/18/2014
From:	Gullott D Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-14-337
Download: ML14352A204 (37)

Text

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=r* Exelon Generation RS-14-337 10 CFR 50.90 December 18, 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 for Diesel Generator Load Rejection Surveillance Requirement 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 proposed amendment revises Technical Specifications (TS) Surveillance Requirement (SR) 3.8.1.10.

The proposed change increases the voltage limit for the diesel generator (DG) full load rejection test specified by IS SR 3.8.1.10. By increasing the voltage limit for the full load rejection test, this resolves an existing non-conservative TS for the voltage that is maintained during a DG full load rejection test. Additionally, the proposed amendment adds Note 3 to IS SR 3.8.1.10 for alignment with the Standard Technical Specifications documented in NUREG-1431. The proposed note allows for full load reject testing in accordance with Regulatory Guide 1.9, Revision 3, "Selection, Design, Qualification, and Testing of Emergency Diesel Generator Units Used as Class lE Onsite Electric Power Systems at Nuclear Power Plants."

The current IS SR 3.8.1.10 was determined to be non-conservative with respect to the voltage limit specified during and following a full load reject test. Administrative controls are currently in place to address this IS non-conservatism in accordance with 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 Braidwood Station and Byron Station. 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 IS and is not a voluntary request to change the Braidwood Station and Byron Station's licensing basis. Therefore, this request is not 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.

December 18, 2014 U.S. Nuclear Regulatory Commission Page 2 The attached request is subdivided as follows:

Attachment 1 provides an evaluation of the proposed change.

Attachments 2 and 3 include the marked-up TS pages with the proposed change indicated for the Braidwood Station and the Byron Station, respectively.

Attachments 4 and 5 include the marked-up TS Bases pages with the proposed change indicated for the Braidwood Station and the Byron Station, respectively. The TS Bases pages are provided for information only and do not require NRC approval.

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.

EGC requests approval of the proposed license amendment by December 18, 2015. Once approved, the amendment will be implemented within 60 days.

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.

There are no regulatory commitments contained in this letter. Should you have any questions concerning this letter, please contact Jessica Krejcie at (630) 657-2816.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 18th day of December 2014.

Respectfully, 41/

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

1. Evaluation of Proposed Change

2. Markup of Technical Specifications Pages for Braidwood Station, Units 1 and 2

3. Markup of Technical Specifications Pages for Byron Station, Units 1 and 2

4. Markup of Technical Specifications Bases Pages for Braidwood Station, Units 1 and 2

5. Markup of Technical Specifications Bases Pages for Byron Station, Units 1 and 2 cc: NRC Regional Administrator, Region III NRC Senior Resident Inspector, Braidwood Station NRC Senior Resident Inspector, Byron Station NRC Project Manager, NRR Braidwood and Byron Stations Illinois Emergency Management Agency Division of Nuclear Safety

ATTACHMENT 1 Evaluation of Proposed Change

Subject:

License Amendment Request for Diesel Generator Load Rejection Surveillance Requirement 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION

4.0 REGULATORY EVALUATION

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

6.0 REFERENCES

Page 1

ATTACHMENT 1 Evaluation of Proposed Change 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 (EGO) 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. The proposed change increases the voltage limit for the diesel generator (DG) full load rejection test specified by Technical Specification (TS) Surveillance Requirement (SR) 3.8.1.10. By increasing the voltage limit for the full load rejection test, this resolves an existing non-conservative TS for the voltage that is maintained during a DG full load rejection test. Additionally, the proposed amendment adds Note 3 to TS SR 3.8.1.10 for alignment with the Standard Technical Specifications documented in NUREG-1431.

The current TS SR 3.8.1.10 was determined to be non-conservative with respect to the voltage limit specified during and following a full load reject test. Administrative controls are currently in place to address this TS non-conservatism in accordance with 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 Braidwood Station and Byron Station. Consistent with the guidance in AL 98-10, EGO is submitting the proposed change as a required license amendment request to resolve a non-conservative TS and is not a voluntary request to change the Braidwood Station and Byron Station licensing basis.

The purpose of the revised SR 3.8.1.10 is to redefine a new maximum DG voltage limit for the full load rejection test. The new maximum DG voltage limit will allow full load reject testing to be performed per NRC Regulatory Guide (RG) 1.9 Revision 3, "Selection, Design, Qualification, and Testing of Emergency Diesel Generator Units Used as Class lE Onsite Electric Power Systems at Nuclear Power Plants." RG 1.9 Revision 3 states in Section 0.2.2.8 that the DG full load reject test should be performed at a power factor between 0.8 and 0.9. However, Byron Station and Braidwood Station took exception to this power factor requirement as documented in the UFSAR Appendix A discussion for Regulatory Guide 1.9. UFSAR Appendix A states that the DG full load reject test specified by Regulatory Guide 1.9 Revision 3 Section 0.2.2.8 is considered to border on destructive testing and can cause premature generator aging. This RG 1.9 Revision 3 exception was established from a ComEd (now EGO) Corporate Engineering Position Paper on Power Factor Loading During Emergency Diesel Generator Testing dated November 28, 1995. As a result of this exception, the Byron Station and Braidwood Station surveillance procedures have been performing the DG full load reject testing required by Technical Specification SR 3.8.1.10 at a power factor > 0.9.

Byron Station Issue Report (IR) 1250432, dated August 8, 2011, documented that the NRC questioned the accuracy and rigor of the previous Corporate Engineering Position Paper and UFSAR position regarding DG full load reject testing at rated power factor as being potentially destructive testing since numerous other utilities perform this same activity with no exceptions to Regulatory Guide 1.9 Revision 3. Based upon additional reviews, it has been determined that the original position that DG full load reject testing at rated power factor is potentially destructive testing was overly conservative and that it is acceptable to perform DG full load reject testing as specified by Regulatory Guide 1.9 Revision 3. In addition, more recent full load reject tests have been successfully performed on all eight of the Byron Station and Braidwood Station DGs (i.e., four DGs per station) at a power factor between 0.8 and 0.9 and have demonstrated that Page 2

ATTACHMENT 1 Evaluation of Proposed Change the higher peak voltages will not damage the DGs. However, in order to support this testing at a lower power factor, a revision to the maximum DG voltage specified in TS SR 3.8.1.10 for full load reject testing is required.

Additionally, the proposed SR contains a new note, which requires that if the DG full load rejection test is performed with the DG synchronized with offsite power it shall be performed at a power factor less than or equal to 0.89. The new note also states that if grid conditions do not permit, the maximum power factor limit is not required to be met and the power factor shall be maintained as close to the limit as practical. The new note ensures that the DG is tested under load conditions that are as close to design basis conditions as practicable. Recent surveillance test results have demonstrated that a power factor greater than 0.8 and less than 0.89 can be achieved for all DGs.

The proposed schedule to review this request is for one year, with approval by December 18, 2015. Implementation is planned for 60 days following the date of approval.

2.0 DETAILED DESCRIPTION SR 3.8.1.10 currently states:

SR 3.8.1.10 NOTES

1. Momentary transients above the voltage limit immediately following a load rejection do not invalidate this test.

2. This Surveillance shall not be performed in MODE 1 or 2.

Verify each DG does not trip and voltage is maintained 4784 V during and following a load rejection of .? 4950 kW and 5 5500 kW.

The proposed change revises the SR to state:

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ATTACHMENT 1 Evaluation of Proposed Change SR 3.8.1.10 NOTES

1. Momentary transients above the voltage limit immediately following a load rejection do not invalidate this test.

2. This Surveillance shall not be performed in MODE 1 or 2.

3. If performed with DG synchronized with offsite power, it shall be performed at a power factor < 0.89. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable.

Verify each DG does not trip and voltage is maintained 5 5600 V during and following a load rejection of 4950 kW and 5500 kW A markup of the proposed TS changes is provided in Attachments 2 and 3. Attachments 4 and 5 provide a markup of the affected Bases pages. The TS Bases pages are provided for information only and do not require NRC approval.

3.0 TECHNICAL EVALUATION

The Byron Station and Braidwood Station DGs are safety related and are classified as Seismic Category I components. Two independent and redundant DGs are provided for each unit. The DGs are the onsite emergency power sources and provide power for safe shutdown and to mitigate the consequences of design basis accidents in the event that offsite power is not available as discussed in UFSAR Section 8.3.

Each DG is rated for 100% full load operation at an Apparent Power value of 6875 kVA and at a power factor of 0.8. This is equal to operation at a Real Power value of 5500 kW and a Reactive Power value of 4125 kVAR. The DGs are designed for operation at rated full load and to survive a trip from full load without damage. Engineering Evaluation 399685, "Evaluation of Diesel Generator Full Load Reject Testing at Rated Power Factor to Support an [a] LAR to Revise Tech Spec SR 3.8.1.10," dated November 21, 2014 concluded that performing a DG full load reject test at the rated power factor of 0.8 or higher will not challenge the DG beyond its ratings based on evaluation of limited risk to winding insulation and recent testing performed verifying that no equipment issues are created and there are no concerns for damage.

Section C.2.2.8 of Regulatory Guide 1.9 Revision 3 states that a full load reject test needs to demonstrate that the DG has the capability to reject a load equal to 90 to 100 percent of its continuous rating while operating at a power factor between 0.8 and 0.9 without exceeding any Page 4

ATTACHMENT 1 Evaluation of Proposed Change maximum voltage requirements and without the DG tripping on overspeed. This Regulatory Guide 1.9 Revision 3 guidance for a DG full load reject test is implemented by Byron Station and Braidwood Station Technical Specification Surveillance Requirement (SR) 3.8.1.10.

A load equal to 90 to 100% of its continuous ratings corresponds to 4950 to 5500 kW, which are the loading values specified in TS SR 3.8.1.10. The proposed TS SR 3.8.1.10 to define a new maximum DG voltage limit for the full load reject test (i.e., from 5 4784 V to 5 5600 V) will not impact the kW loading requirements specified in TS SR 3.8.1.10 and Regulatory Guide 1.9, nor does it change the requirement that the DG not trip following a full load reject. The proposed TS SR does not affect the minimum specified power factor value of 0.8 from Regulatory Guide 1.9.

This value equals the DG rating and is acceptable as a lower limit for the power factor range for DG full load reject testing. However, the upper power factor limit of 0.9 from Regulatory Guide 1.9 will be lowered slightly to bound the actual Byron/Braidwood DG loading conditions.

This is conservative since for a given real power (kW) load, a lower power factor value indicates that there is more inductive load and more overall current load on the DG.

3.1 Evaluation of Power Factor KCI Evaluation 425-023-DC1, "Determine the maximum generator voltage magnitude on a full load reject test when operated at rated and unity power factor. Assess the risk of damage to the diesel generator winding insulation," Revision 1, dated August 19, 2013, determines the maximum diesel generator voltage on a full load reject test when operated at rated (i.e., 0.8) and unity (i.e., 1.0) power factor. This evaluation also assessed the risk of damage to the diesel generator winding insulation.

Standard synchronous machine models and equations were used to calculate voltages and currents in the direct and quadrature axes, where the direct axis is defined as being in the direction of the rotor field winding and the quadrature axis is defined as being 90 degrees after the direct axis. These equations and inputs were then used to calculate the maximum DG output terminal voltage during a full load rejection. Saturated generator reactance values were used consistent with standard practice for evaluating generator performance during operation at normal rated load conditions.

The Byron Station and Braidwood Station DGs are rated as follows:

Apparent Power Rating = 6875 kVA Rated Voltage = 4160 Volts Rated Power Factor = 0.8 Rated Amps = 954.2 Amps The evaluation assumed that the DG was initially operating at 4580 volts, which is the maximum allowed steady state voltage in IS 3.8.1. This is conservative since the intent is to determine the maximum voltage during a full load reject test. The evaluation also conservatively did not credit operation of the voltage regulator, which would reduce excitation following a full load reject and limit the voltage transient.

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ATTACHMENT 1 Evaluation of Proposed Change Using these inputs and models, the KCI evaluation determined that the maximum DG voltage during a full load reject test at rated and unity power factor would be as follows:

DG Voltage = 1.335 per unit (pu) = 5554 Volts (Power Factor = 0.8)

DG Voltage = 1.14 pu = 4742 Volts (Power Factor = 1.0)

(Note that DG Voltage = Vpu x Vbase, where Vbase = 4160 Volts.)

These voltage values are the bounding maximum DG voltages expected for a full load reject test at rated and unity power factors.

3.2 Evaluation of proposed DG Maximum Voltage Limits High potential insulation testing is periodically performed to assess the insulation condition of the DG stator windings per Exelon Standard NES-EIC-17.03, "High Potential Tests." According to Exelon Standard NES-EIC-17.03 "High Potential Tests," and IEEE 95, "IEEE Recommended Practice for Insulation Testing of AC Electric Machinery (2300 V and Above) With High Direct Voltage," (Reference 1) periodic testing of in-service generator stator windings is performed at an AC test voltage of 1.5E, where E = the rated voltage. Therefore, for the Byron Station and Braidwood Station DGs, the test voltage of 1.5E = 1.5 x 4160 Volts = 6240 Volts. The test voltage of 6240 Volts is applied for one minute between each phase and ground with the other two phases grounded.

The maximum calculated DG full load reject voltage of 5554 Volts is less than the high potential insulation test voltages of 6240 Volts. In addition, the peak voltage during a full load reject test will only be experienced for a few seconds. The voltage regulator will quickly reduce the DG output voltage. Therefore, the maximum calculated voltage during a DG full load reject test at rated power factor is bounded by the high potential insulation test voltage and is acceptable.

Therefore, to provide a small amount of additional margin for DG full load testing, the maximum calculated voltage of 5554 Volts will be rounded up to 5600 Volts. The value of 5600 Volts is bounded by the DG stator winding limit of 6240 Volts and provides about 11% margin between these two values.

3.3 Byron Station and Braidwood Station DG Full Load Reject Test Data Byron Station and Braidwood Station have performed DG full load reject testing at a power factor between 0.8 and 0.9 in accordance with Regulatory Guide 1.9 Revision 3 to gather data and to verify that actual DG performance is bounded by the calculated values. The testing also verified that the DG full load reject testing can be performed per the Regulatory Guide 1.9 Revision 3 guidance without creating any equipment issues or damage concerns. The test data is summarized below.

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ATTACHMENT 1 Evaluation of Proposed Change Table 1: Byron Station and Braidwood Station Maximum DG Voltage during DG Full Load Reject Testing DG Byron Station Braidwood Station 1A 5031 Volts 4907 Volts 1B 5009 Volts 4907 Volts 2A 4813 Volts 4851 Volts 2B 5031 Volts 4891 Volts As shown above, all of the test data is bounded by the calculated value of 5554 Volts, and there is significant margin between the highest test data voltage of 5031 Volts and the calculated voltage of 5554 Volts.

3.4 Addition of Standard Note from the Standard Technical Specifications Regarding the Required Power Factor during DG Full Load Reject Testing with High Grid Voltages As part of the proposed IS SR to revise the DG maximum voltage during full load reject testing, EGC also requests NRC approval to add an allowance note from the Standard Technical Specifications (NUREG-1431) regarding the required power factor during DG full load reject testing with high grid voltages. NUREG-1431, Note 2 for SR 3.8.1.10 states the following:

"If performed with DG synchronized with offsite power, it shall be performed at a power factor

<[0.9]. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable."

For Byron Station and Braidwood Station, this allowance note is proposed to be added as Note 3 to SR 3.8.1.10. This allowance note provides operational flexibility for performing the surveillance during high grid voltage conditions when the grid loading may be lower than normal. During high grid voltage conditions, it may not be possible to achieve the preferred power factor loading on the DG without either exceeding an Engineered Safety Features bus voltage limit or the DG exciter current limit. Without this allowance note, during high grid voltage conditions, the surveillance may need to be stopped and rescheduled to be performed during lower grid voltage conditions. With this allowance note in place, during high grid voltage conditions, the operators would be able to load the DG to the best achievable power factor and continue with the surveillance.

The lowest power factor values as documented in the Byron Station and Braidwood Station DG loading calculations are as follows:

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ATTACHMENT 1 Evaluation of Proposed Change Table 2: Byron Station and Braidwood Station DG Loading Calculation Lowest Required Power Factor Station Calculation Calculation title Power DG kW kVA Number Factor Byron 19-T-5 Diesel Generator 1A 3344 3735 0.895 Loading during Loss of Offsite Power (LOOP) /Loss of Coolant Accident (LOCA)

Byron 19-T-5 Diesel Generator 1B 3487 3909 0.892 Loading during LOOP/LOCA Braidwood 19-T-6 Diesel Generator 1A 3196 3567 0.896 Loading during LOOP/LOCA Braidwood 19-T-6 Diesel Generator 1B 3261 3652 0.893 Loading during LOOP/LOCA Byron 19-T-3 Station Blackout- DG 1A 5830 6445 0.905 Loading Braidwood 19-T-3 Station Blackout- DG 1A 5840 6457 0.904 Loading Byron 19-T-4 Station Blackout- DG 1A 5918 6536 0.905 Loading (Including MCC 231Z1 Load)

Note that per the calculations listed in the table, the Unit 1 DG loadings are greater than the Unit 2 DG loadings and will bound the Unit 2 DG loadings. This is because the Unit 1 DGs have more inductive loads (e.g., Control Room Refrigeration Units, Control Room Supply Fans, and Control Room Return Fans) than the Unit 2 DGs. For a given kW loading, a lower PF indicates that there is more inductive loading and is more demanding on the DG because it involves a higher overall current value. Therefore, the Unit 1 DG PF values are less than the Unit 2 DG PF values and will bound the Unit 2 DG PF values.

In the allowance note from the Standard Technical Specifications, the Power Factor of 0.9 is in brackets and based on the table above, a Power Factor of 89.0% was selected as a bounding value to be used in the new allowance note for performance of DG full load reject testing during high grid voltage conditions. Therefore, the normal Power Factor range for DG full load reject testing will be > 0.80 and < 0.89. This selected range is bounded by the Power Factor values specified in Section 0.2.2.8 of Regulatory Guide 1.9 Revision 3 (i.e., Power Factor > 0.8 and

<0.9).

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ATTACHMENT 1 Evaluation of Proposed Change

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria The following NRC requirements and guidance documents are applicable to the review of the proposed changes:

10 CFR 50.36(c)(3), "Surveillance requirements," requires that TSs include SRs, which are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.

Regulatory Guide 1.9, Revision 3, "Selection, Design, Qualification, and Testing of Emergency Diesel Generator Units Used as Class lE Onsite Electric Power Systems at Nuclear Power Plants," provides guidance for complying with the NRC Commission's requirements that DG units intended for use as onsite emergency power sources in nuclear power plants be selected with sufficient capacity, be qualified, and have the necessary reliability and availability for station blackout and design basis accidents.

NUREG-1431, "Standard Technical Specification Westinghouse Plants," contains the improved Standard Technical Specifications (STS) for Westinghouse plants. The improved STS were developed based on the criteria in the Final Commission Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors, dated July 22, 1993 which was subsequently codified by changes to Section 36 of Part 50 of Title 10 of the Code of Federal Regulations (10 CFR 50.36) (60 FR 36953). NUREG-1431 states that Licensees are encouraged to upgrade their technical specifications consistent with those criteria.

General Design Criteria (GDC) 17, "Electric Power Systems," requires that onsite electric power systems have sufficient independence, capacity, capability, redundancy and testability to ensure that 1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and

2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents, assuming a single failure.

GDC 18, "Inspection and Testing of Electric Power Systems," of Appendix A to 10 CFR Part 50 requires that electric power systems important to safety be designed to permit appropriate periodic inspection and testing to assess the continuity of the systems and the condition of their components.

The proposed change to SR 3.8.1.10 does not alter the design or function of the DGs and does not result in any change in the qualifications of any component; and does not result in the reclassification of any component's status in the areas of shared, safety-related, independent, redundant, or physical or electrical separation. The proposed change to SR 3.8.1.10 only increases the voltage limit for the full load rejection test and adds a note for alignment with the Standard Technical Specifications documented in NUREG-1431. Increasing the voltage limit, specified in SR 3.8.1.10 resolves a non-conservative TS currently addressed by administrative controls. The proposed note allows for full load reject testing in accordance with Regulatory Guide 1.9, Revision 3, "Selection, Design, Qualification, and Testing of Emergency Diesel Page 9

ATTACHMENT 1 Evaluation of Proposed Change Generator Units Used as Class 1E Onsite Electric Power Systems at Nuclear Power Plants."

Therefore, compliance with the regulatory requirements of 10 CFR 50.36(c)(3), Regulatory Guide 1.9 Revision 3, NUREG-1431, GDC 17 and GDC 18 will be maintained.

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 1 and 2. Specifically, this amendment request proposes to revise Technical Specification (TS) Surveillance Requirement (SR) 3.8.1.10 to increase the voltage limit for the Diesel Generator (DG) full load rejection test, resolving an identified non-conservative TS condition currently administratively controlled in accordance with 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 Braidwood Station and Byron Station. Additionally, the proposed amendment adds Note 3 to TS SR 3.8.1.10 for alignment with the Standard Technical Specifications documented in NUREG-1431. The proposed note allows for full load reject testing in accordance with Regulatory Guide 1.9, Revision 3, "Selection, Design, Qualification, and Testing of Emergency Diesel Generator Units Used as Class lE Onsite Electric Power Systems at Nuclear Power Plants." The Byron Station and Braidwood Station DGs are safety related and are classified as Seismic Category I components. Two independent and redundant DGs are provided for each unit. The DGs are the onsite emergency power sources and provide power for safe shutdown and to mitigate the consequences of design basis accidents in the event that offsite power is not available as discussed in UFSAR Section 8.3.

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.

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ATTACHMENT 1 Evaluation of Proposed Change EGO 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 DGs design function is to mitigate an accident and there are no analyzed scenarios where the DGs are initiators of any previously evaluated accident. Since DGs do not initiate accidents, this change does not increase the probability of occurrence of a previously evaluated accident.

The proposed change to the testing approach of the DGs is consistent with the original design of the DGs. The proposed change is in accordance with RG 1.9 Revision 3, and this change to the testing approach does not impact the DGs ability to mitigate accidents. The DGs will continue to operate within the parameters and conditions assumed within the accident analysis.

This change does not result in an increase in the likelihood of malfunction of the DGs or their supported equipment. Since the DGs will continue to perform its required function, there is no increase in the consequences of previously evaluated accidents.

Therefore, 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 amendment does not change the DGs operation or ability to perform its design function. The proposed change to TS SR 3.8.1.10 at increased voltage will ensure the DGs ability to perform at rated power factor while meeting its requirements. The change to TS SR 3.8.1.10 does not result in DG operation that would create a new failure mode of the DGs that could create a new initiator of an accident. This is because the DGs ability to perform its design function is maintained in the same manner as originally designed. The proposed change does not change the single failure capabilities of the electrical power system or create a potential for loss of power since the design operation of the DGs is maintained.

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

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ATTACHMENT 1 Evaluation of Proposed Change

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

Response: No The margin of safety is established through the design of the plant structures, systems, and components, the parameters within which the plant is operated, and the setpoints for the actuation of equipment relied upon to respond to an event. The proposed change does not modify the safety limits or setpoints at which protective actions are initiated. The proposed change increases the voltage limit for the DG full load rejection test which results in new test acceptance criterion that is more restrictive than the existing acceptance criteria. The proposed change ensures the availability and operability of safety-related DGs. Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above evaluation, EGO concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92, paragraph (c),

and accordingly, a finding of no significant hazards consideration is justified.

4.3 Conclusion 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 Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

EGC has determined that the proposed amendment would change 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." However, the proposed amendment does not involve: (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review,"

paragraph (c)(9). Therefore, pursuant to 10 CFR 51.22, paragraph (b), no environmental impact statement or environmental assessment needs to be prepared in connection with the proposed amendment.

6.0 REFERENCES

1. IEEE Standard 95-2002, "IEEE Recommended Practice for Insulation Testing of AC Electric Machinery (2300 V and Above) With High Direct Voltage" Page 12

ATTACHMENT 2 Markup of Technical Specifications Pages for Braidwood Station, Units 1 and 2 Braidwood Station, Units 1 and 2 Facility Operating License Nos. NPF-72 and NPF-77 AFFECTED TECHNICAL SPECIFICATIONS PAGES 3.8.1-7

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.9 NOTE This Surveillance shall not be performed in MODE 1 or 2.

Verify each DG rejects a load greater than In accordance or equal to its associated single largest with the post-accident load, and: Surveillance Frequency

a. Following load rejection, the Control Program frequency is 64.5 Hz;

b. Following load rejection, the steady state voltage is maintained ?_ 3950 V and 4580 V; and

c. Following load rejection, the steady state frequency is maintained 58.8 Hz and 61.2 Hz.

SR :3.8.1.10 NOTES I. Momentary transients above the voltage limit immediately following a load rejection do not invalidate this test.

2. This Surveillance shall not he performed in MODE 1 or 2.

3. If performed with DG synchronize° witn offsite power, it shall be performed at a power factor 5 0.89. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable.

Verify each DG does not trip and voltage is In accordance maintained 1781 501D_V during and with the following a load rejection of 4950 kW and Surveillance 5500 kW. Frequency Control Program (continued)

BRAIDWOOD UNITS 1 & 2 3.8.1 7 Amendment

ATTACHMENT 3 Markup of Technical Specifications Pages for Byron Station, Units 1 and 2 Byron Station, Units 1 and 2 Facility Operating License Nos. NPF-37 and NPF-66 AFFECTED TECHNICAL SPECIFICATIONS PAGES 3.8.1-5 3.8.1-6 3.8.1-7 3.8.1-8 (NOTE: Additional pages are included for Byron Station Technical Specifications that are not included for Braidwood Station due to pagination issues only)

AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and In accordance indicated power availability for each with the required qualified circuit. Surveillance Frequency Control Program SR 3.8.1.2 NOTE A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met. Performance of SR 3.8.1.7 satisfies this SR.

Verify each DG starts from standby In accordance condition and achieves steady state voltage with the 3950 V and 4580 V and frequency 58.8 Surveillance Hz and 61.2 Hz. Frequency Control Program SR 3.8.1.3 NOTES

1. DG loadings may include gradual loading as recommended by the manufacturer.

2. Momentary transients outside the load range do not invalidate this test.

3. This Surveillance shall be conducted on only one DG at a time.

4. This Surveillance shall be preceded by and immediately follow without shutdown a successful performance of SR 3.8.1.2 or SR 3.8.1.7.

Verify each DG is synchronized and loaded In accordance and operates for 60 minutes at a load with the 4950 kW and 5500 kW. Surveillance Frequency Control Program (continued)

BYRON UNITS 1 & 2 3.8.1 5 Amendment

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.4 Verify each day tank contains 450 gal of In accordance fuel oil. with the Surveillance Frequency Control Program SR 3.8.1.5 Check for and remove accumulated water from In accordance each day tank. with the Surveillance Frequency Control Program SR 3.8.1.6 Verify the fuel oil transfer system In accordance operates to automatically transfer fuel oil with the from storage tank(s) to the day tank. Surveillance Frequency Control Program SR 3.8.1.7 Verify each DG starts from normal standby In accordance condition and achieves: with the Surveillance

a. In 10 seconds, voltage 3950 V Frequency and frequency 58.8 Hz; and Control Program

b. Steady state voltage 3950 V and 4580 V, and frequency 58.8 Hz and 61.2 Hz.

SR 3.8.1.8 Verify manual transfer of AC power sources In accordance from the required normal qualified with the circuit(s) to the reserve required Surveillance qualified circuit(s). Frequency Control Program (continued)

BYRON UNITS 1 & 2 3.8.1 6 Amendment

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.9 NOTE This Surveillance shall not be performed in MODE 1 or 2.

Verify each DG rejects a load greater than In accordance or equal to its associated single largest with the post-accident load, and: Surveillance Frequency

a. Following load rejection, the Control Program frequency is 64.5 Hz;

b. Following load rejection, the steady state voltage is maintained 3950 V and 4580 V; and

c. Following load rejection, the steady state frequency is maintained 58.8 Hz and 61.2 Hz.

SR 3.8.1.10 NOTES

1. Momentary transients above the voltage limit immediately following a load rejection do not invalidate this test.

2. This Surveillance shall not be performed in MODE 1 or 2.

3. If performed with DG synchronized with offsite power, it shall be performed at a power factor 5 0.89. However, if grid conditions do not permit, the power factor limit is not required tq be met. Under this condition the power factor shall be maintained as close to the limit as practicable.

Verify each DG does not trip and voltage is In accordance maintained 478/1 5600 V during and with the following a load rejection of 4950 kW and Surveillance 5500 kW. Frequency Control Program (continued)

BYRON UNITS 1 & 2 3.8.1 7 Amendment

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.11 NOTE This Surveillance shall not be performed in MODE 1, 2, 3, or 4.

Verify on an actual or simulated loss of In accordance offsite power signal: with the Surveillance

a. De-energization of [SF buses; Frequency Control Program

b. Load shedding from ESF buses; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in 10 seconds,

2. energizes auto-connected shutdown loads through the shutdown load sequence timers,

3. maintains steady state voltage 3950 V and 4580 V,

4. maintains steady state frequency 58.8 Hz and 61.2 Hz, and

5. supplies permanently connected and auto-connected shutdown loads for 5 minutes.

(continued)

BYRON UNITS 1 & 2 3.8.1 8 Amendment

ATTACHMENT 4 Markup of Technical Specifications Bases Pages for Braidwood Station, Units 1 and 2 Braidwood Station, Units 1 and 2 Facility Operating License Nos. NPF-72 and NPF-77 AFFECTED TECHNICAL SPECIFICATIONS BASES PAGES B 3.8.1-22 B 3.8.1-23 B 3.8.1-24 B 3.8.1-25 B 3.8.1-26 B 3.8.1-27 B 3.8.1-28 (NOTE 1: TS Bases pages are provided for information only.)

(NOTE 2: Additional TS Bases Pages are included due to pagination issues only)

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine/generator response under the simulated test conditions. This test simulates a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection. While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

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

This SR has been modified by 4eLethree_Notes. Note 1 states that momentary transients above the stated voltage limit immediately following a load rejection (i.e., the DG full load rejection) do not invalidate this test. The momentary transient is that which occurs immediately after the circuit breaker is opened, lasts a few milliseconds, and may or may not be observed on voltage recording or monitoring instrumentation. The reason for Note 2 is that during operation with the reactor critical, performance of this SR could cause perturbation to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems Note 3 ensures that the DG is tested under load _ ons that are as close to design basis conditions as possible. When synchronized with offsite power, testing should be performed at a power factor of 0.89. This power factor is representative of the actual inductive loading a DG would experience under design basis accident conditions. Under certain conditions; however, Note 3 allows the Surveillance to be conducted at a power factor other than 0.89. These conditions occur when grid voltage is high, and the additional field excitation needed to get the power factor to 0.89 results in voltages on the emergency busses that are too high. Under these conditions, the power factor should be maintained as close as practicable to 0.89 while still maintaining acceptable voltage limits on the emergency busses. In other circumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power BRAIDWOOD UNITS 1 & 2 B 3.8.1 22 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) factor of 0.89 may not cause unacceptable voltages on the emergency busses, but the excitation levels are in excess of those recommended for the DG. In such cases, the power factor shall be maintained as close as practicable to 0.89 without exceeding the DG excitation limits.

SR 3.8.1.11 In general conformance with the recomendations of Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.4, this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source.

This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the DG. It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time, and maintain a steady state voltage and frequency range.

The DG autostart time of 10 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability is achieved.

The requirement to verify the connection and power supply of permanent and autoconnected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or Residual Heat Removal (RHR) systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

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

BRAIDWOOD UNITS 1 & 2 B 3.8.1 23 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates for 5 minutes.

The 5 minute period provides sufficient time to demonstrate stability.

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

SR 3.8.1.13 This Surveillance demonstrates that DG noncritical protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal. The noncritical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not imediately detrimental to emergency operation of the DG.

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

SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.9, recommends demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load band equivalent to 105% to 110% of the continuous duty rating and the remainder of the time at a load equivalent to the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are also applicable to this SR.

BRAIDWOOD UNITS 1 & 2 B 3.8.1 24 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

In order to ensure that the DG is tested under load conditions that bound design conditions and comply with the reconuendations of Regulatory Guide 1.9 (Ref. 3) paragraph 2.2.9, testing must be performed using a power factor 0.8 and 0.89. This power factor range bounds the actual design basis inductive loading the DG would experience. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor reconmendations in order to maintain DG OPERABILITY.

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

This Surveillance is modified by a Note which states that momentary transients (e.g., due to changing bus loads) do not invalidate this test.

SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 10 seconds. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. Alternatively, the DG can be operated until operating temperatures have stabilized. Note 2 states that momentary transients (e.g., due to changing bus loads) do not invalidate this test.

BRAIDWOOD UNITS 1 & 2 B 3.8.1 25 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.16 As required by Regulatory Guide 1.9 (Ref. 3),

paragraph 2.2.11, this Surveillance ensures that the manual synchronization and load transfer from the DG to the offsite source can be made and the DG can be returned to ready to load status when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in ready to load status when the DG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.

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

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions will not be compromised as the result of testing and the DG will automatically reset to ready to load operation if a LOCA actuation signal is received during operation in the test mode. Ready to load operation is defined as the DG running at rated speed and voltage with the DG output breaker open.

These provisions for automatic switchover are required by IEEE-308 (Ref. 10), paragraph 6.2.6(2).

The intent in the requirement associated with SR 3.8.1.17.b is to show that the emergency loading was not affected by the DG operation in test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

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

BRAIDWOOD UNITS 1 & 2 B 3.8.1 26 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.18 Under accident and loss of offsite power conditions, loads are sequentially connected to the bus by the automatic load sequence timers. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents.

The 10% load sequence time interval tolerance ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a sunuory of the automatic loading of ESF buses.

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

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ESF actuation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

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

BRAIDWOOD UNITS 1 & 2 B 3.8.1 27 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

This SR is modified by a Note. The reason for the Note is that the performance of the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

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

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. UFSAR, Chapter 8.

3. Regulatory Guide 1.9, Rev. 3, July 1993.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

6. Regulatory Guide 1.93, Rev. 0, December 1974.

7. R. M. Krich to NRC Document Control Desk Letter, "Request for Amendment to Technical Specifications, to Facility Operating Licenses, Emergency Diesel Generators, Completion Time Extension and Surveillance Requirement Change," January 20, 2000.

8. Generic Letter 84-15, "Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability,"

July 2, 1984.

9. 10 CFR 50, Appendix A, GDC 18.

10. IEEE Standard 308-1978.

11. Regulatory Guide 1.137, Rev. 1, October 1979.

BRAIDWOOD UNITS 1 & 2 B 3.8.1 28 Revision

ATTACHMENT 5 Markup of Technical Specifications Bases Pages for Byron Station, Units 1 and 2 Byron Station, Units 1 and 2 Facility Operating License Nos. NPF-37 and NPF-66 AFFECTED TECHNICAL SPECIFICATIONS BASES PAGES B 3.8.1-22 B 3.8.1-23 B 3.8.1-24 B 3.8.1-25 B 3.8.1-26 B 3.8.1-27 B 3.8.1-28 (NOTE 1: TS Bases pages are provided for information only.)

(NOTE 2: Additional TS Bases Pages are included due to pagination issues only)

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. Tie DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine/generator response under the simulated test conditions. This test simulates a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection. While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

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

This SR has been modified by two three Notes. Note 1 states that momentary transients above the stated voltage limit immediately following a load rejection (i.e., the DG full load rejection) do not invalidate this test. The momentary transient is that which occurs immediately after the circuit breaker is opened, lasts a few milliseconds, and may or may not be observed on voltage recording or monitoring instrumentation. The reason for Note 2 is that during operation with the reactor critical, performance of this SR could cause perturbation to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems. Note 3 ensures that the DG is tested under load conditions that are as close to design basis conditions as possible. When synchronized with offsite power, testing should be performed at a power factor of 0.89. This power factor is representative of the actual inductive loading a DG would experience under design basis accident conditions. Under certain conditions; however, Note 3 allows the Surveillance to be conducted at a power factor other than 0.89. These conditions occur when grid voltage is high, and the additional field excitation needed to get the power factor to 0.89 results in voltages on the emergency busses that are too high. Under these conditions, the power factor should be maintained as close as practicable to 0.89 while still maintaining acceptable voltage limits on the emergency busses. In other circumstances, the grid voltage mu be such that the DG excitation levels needed to obtain a power BYRON UNITS 1 & 2 B 3.8.1 22 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) factor of 0.89 may not cause unacceptable voltages on the emergency busses, but the excitation levels are in excess of those recommended for the DG. In such cases, the power factor shall be maintained as close as practicable to 0.89 without exceeding the DG excitation limits.

SR 3.8.1.11 In general conformance with the recommendations of Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.4, this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source.

This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the DG. It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time, and maintain a steady state voltage and frequency range.

The DG autostart time of 10 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability is achieved.

The requirement to verify the connection and power supply of permanent and autoconnected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or Residual Heat Removal (RHR) systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

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

BYRON UNITS 1 & 2 B 3.8.1 23 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frecuency within the specified time (10 seconds) from the cesign basis actuation signal (LOCA signal) and operates for 5 minutes.

The 5 minute period provides sufficient time to demonstrate stability.

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

SR 3.8.1.13 This Surveillance demonstrates that DG noncritical protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal. The noncritical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

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

SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.9, recommends demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load band equivalent to 105% to 110% of the continuous duty rating and the remainder of the time at a load equivalent to the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are also applicable to this SR.

BYRON UNITS 1 & 2 B 3.8.1 24 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

In order to ensure that the DG is tested under load conditions that bound design conditions and comply with the recommendations of Regulatory Guide 1.9 (Ref. 3) paragraph 2.2.9, testing must be performed using a power factor 0.8 and 0.89. This power factor range bounds the actual design basis inductive loading the DG would experience. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor reconuendations in order to maintain DG OPERABILITY.

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

This Surveillance is modified by a Note which states that momentary transients (e.g., due to changing bus loads) do not invalidate this test.

SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 10 seconds. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. Alternatively, the DG can be operated until operating temperatures have stabilized. Note 2 states that momentary transients (e.g., due to changing bus loads) do not invalidate this test.

BYRON UNITS 1 & 2 B 3.8.1 25 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.16 As required by Regulatory Guide 1.9 (Ref. 3),

paragraph 2.2.11, this Surveillance ensures that the manual synchronization and load transfer from the DG to the offsite source can be made and the DG can be returned to ready to load status when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in ready to load status when the DG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.

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

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions will not be compromised as the result of testing and the DG will automatically reset to ready to load operation if a LOCA actuation signal is received during operation in the test mode. Ready to load operation is defined as the DG running at rated speed and voltage with the DG output breaker open.

These provisions for automatic switchover are required by IEEE-308 (Ref. 10), paragraph 6.2.6(2).

The intent in the requirement associated with SR 3.8.1.17.b is to show that the emergency loading was not affected by the DG operation in test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

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

BYRON UNITS 1 & 2 B 3.8.1 26 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.18 Under accident and loss of offsite power conditions, loads are sequentially connected to the bus by the automatic load sequence timers. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents.

The 10% load sequence time interval tolerance ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a summary of the automatic loading of ESF buses.

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

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ESF actuation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

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

BYRON UNITS 1 & 2 B 3.8.1 27 Revision

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

This SR is modified by a Note. The reason for the Note is that the performance of the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

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

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. UFSAR, Chapter 8.

3. Regulatory Guide 1.9, Rev. 3, July 1993.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

6. Regulatory Guide 1.93, Rev. 0, December 1974.

7. R. M. Krich to NRC Document Control Desk Letter, "Request for Amendment to Technical Specifications, to Facility Operating Licenses, Emergency Diesel Generators, Completion Time Extension and Surveillance Requirement Change," January 20, 2000.

8. Generic Letter 84-15, "Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability,"

July 2, 1984.

9. 10 CFR 50, Appendix A, GDC 18.

10. IEEE Standard 308-1978.

11. Regulatory Guide 1.137, Rev. 1, October 1979.

BYRON UNITS 1 & 2 B 3.8.1 28 Revision