ML23349A162

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Issuance of Amendment Nos. 298 and 294 Increase Completion Time in Technical Specification 3.8.1.B.4 (Emergency Circumstances)
ML23349A162
Person / Time
Site: Quad Cities  Constellation icon.png
Issue date: 12/17/2023
From: Robert Kuntz
Plant Licensing Branch III
To: Rhoades D
Constellation Energy Generation, Constellation Nuclear
Kuntz R
References
EPID L-2023-2023-0171
Download: ML23349A162 (37)
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Text

December 17, 2023 Mr. David P. Rhoades Senior Vice President Constellation Energy Generation, LLC President and Chief Nuclear Officer Constellation Nuclear 4300 Winfield Road Warrenville, IL 60555

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT NOS. 298 AND 294 RE: INCREASE COMPLETION TIME IN TECHNICAL SPECIFICATION 3.8.1.B.4 (EMERGENCY CIRCUMSTANCES)

(EPID L-2023-LLA-0171)

Dear Mr. Rhoades:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 298 to Renewed Facility Operating License No. DPR-29 and Amendment No. 294 to Renewed Facility Operating License No. DPR-30 for the Quad Cities Nuclear Power Station (Quad Cities), Units 1 and 2, respectively. The amendments consist of changes to the technical specifications (TSs) in response to your application dated December 13, 2023, as supplemented by letter dated December 15, 2023.

The amendments revise TS 3.8.1, AC [alternating current] Sources-Operating, Condition B, One required DG [diesel generator] inoperable, required action B.4 Restore required DG to OPERABLE status to provide a one-time extension of the completion time from 7 days to 14 days. The amendments also revise surveillance requirements for testing of the Quad Cities, Unit 2, DG and the common DG during the extended period that the Quad Cities, Unit 1, DG is inoperable.

The license amendment is issued under emergency circumstances as provided in the provisions of paragraph 50.91(a)(5) of Title 10 of the Code of Federal Regulations due to the time critical nature of the amendment. In this instance, an emergency situation exists due to unplanned failure of the Quad Cities, Unit 1, DG during monthly load testing. Because of the failure, both Quad Cities units remain in TS 3.8.1, condition B which requires restoration of the inoperable DG within 7 days. If the inoperable DG cannot be returned to service within 7 days, then applicable surveillance requirements and TS 3.8.1 condition F would require the units to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Maintenance activities continue at the site to return the Quad Cities, Unit 1, DG to operable but the activities are not expected to be completed within the condition B completion time.

A copy of the related safety evaluation is also enclosed. The safety evaluation describes the emergency circumstances under which the amendment was issued and the final no significant hazards determination. A Notice of Issuance addressing the final no significant hazards

determination and opportunity for a hearing associated with the emergency circumstances will be included in a future monthly Federal Register notice.

Sincerely,

/RA/

Robert F. Kuntz, Senior Project Manager Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-254 and 50-265

Enclosures:

1. Amendment No. 298 to DPR-29
2. Amendment No. 294 to DPR-30
3. Safety Evaluation cc: Listserv

CONSTELLATION ENERGY GENERATION, LLC AND MIDAMERICAN ENERGY COMPANY DOCKET NO. 50 254 QUAD CITIES NUCLEAR POWER STATION, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 298 Renewed License No. DPR-29

1.

The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Constellation Energy Generation, LLC (the licensee) dated December 13, 2023, as supplemented by letter dated December 15, 2023, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 3.B. of Renewed Facility Operating License No. DPR-29 is hereby amended to read as follows:

B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 298, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of the date of its issuance and shall be implemented within 7 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Jeffrey A. Whited, Chief Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: December 17, 2023 Scott P. Wall Digitally signed by Scott P. Wall Date: 2023.12.17 15:11:12 -05'00'

CONSTELLATION GENERATION COMPANY, LLC AND MIDAMERICAN ENERGY COMPANY DOCKET NO. 50-265 QUAD CITIES NUCLEAR POWER STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 294 Renewed License No. DPR-30

1.

The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by the Constellation Generation Company, LLC (the licensee) dated December 13, 2023, as supplemented by letter dated December 15, 2023, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 3.B. of Renewed Facility Operating License No. DPR-30 is hereby amended to read as follows:

B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 294, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of the date of its issuance and shall be implemented within 7 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Jeffery A. Whited, Chief Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Renewed Facility Operating License Date of Issuance: December 17, 2023 Scott P. Wall Digitally signed by Scott P. Wall Date: 2023.12.17 15:12:09 -05'00'

ATTACHMENT TO LICENSE AMENDMENT NOS. 298 AND 294 RENEWED FACILITY OPERATING LICENSE NOS. DPR-29 AND DPR-30 QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 DOCKET NOS. 50-254 AND 50-265 Replace the following pages of the Renewed Facility Operating Licenses and Appendix A, Technical Specifications, with the attached pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert License No. DPR-29 License No. DPR-29 Page 4 Page 4 License No. DPR-30 License No. DPR-30 Page 4 Page 4 TSs TSs 3.8.1-3 3.8.1-3 3.8.1-6 3.8.1-6 3.8.1-7 3.8.1-7 3.8.1-8 3.8.1-8 3.8.1-9 3.8.1-9 3.8.1-10 3.8.1-10 3.8.1-11 3.8.1-11 3.8.1-12 3.8.1-12 3.8.1-13 3.8.1-13 3.8.1-14 3.8.1-14 3.8.1-15 3.8.1-15 3.8.1-16 3.8.3-2 3.8.3-2 3.8.3.3 Renewed License No. DPR-29 Amendment No. 298 B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 298, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

C.

The licensee shall maintain the commitments made in response to the March 14, 1983, NUREG-0737 Order, subject to the following provision:

The licensee may make changes to commitments made in response to the March 14, 1983, NUREG-0737 Order without prior approval of the Commission as long as the change would be permitted without NRC approval, pursuant to the requirements of 10 CFR 50.59. Consistent with this regulation, if the change results in an Unreviewed Safety Question, a license amendment shall be submitted to the NRC staff for review and approval prior to implementation of the change.

D.

Equalizer Valve Restriction Three of the four valves in the equalizer piping between the recirculation loops shall be closed at all times during reactor operation with one bypass valve open to allow for thermal expansion of water.

E.

The licensee shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822), and the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined sets of plans1, which contain Safeguards Information protected under 10 CFR 73.21, is entitled: Quad Cities Nuclear Power Station Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 2, submitted by letter dated May 17, 2006.

Constellation Energy Generation, LLC shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p).

The CSP was approved by License Amendment No. 249 as modified by License Amendment No. 259.

1 The Training and Qualification Plan and Safeguards Contingency Plan are Appendices to the Security Plan.

Renewed License No. DPR-30 Amendment No. 294 B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 294, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

C.

The licensee shall maintain the commitments made in response to the March 14, 1983, NUREG-0737 Order, subject to the following provision:

The licensee may make changes to commitments made in response to the March 14, 1983, NUREG-0737 Order without prior approval of the Commission as long as the change would be permitted without NRC approval, pursuant to the requirements of 10 CFR 50.59. Consistent with this regulation, if the change results in an Unreviewed Safety Question, a license amendment shall be submitted to the NRC staff for review and approval prior to implementation of the change.

D.

Equalizer Valve Restriction Three of the four valves in the equalizer piping between the recirculation loops shall be closed at all times during reactor operation with one bypass valve open to allow for thermal expansion of water.

E.

The licensee shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822), and the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans1, which contain Safeguards Information protected under 10 CFR 73.21, is entitled: Quad Cities Nuclear Power Station Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 2, submitted by letter dated May 17, 2006.

Constellation Energy Generation, LLC shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The CSP was approved by License Amendment No. 244 and modified by License Amendment No. 254.

1 The Training and Qualification Plan and Safeguards Contingency Plan are Appendices to the Security Plan.

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-3 Amendment No. 298/294 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. One required DG inoperable.

B.1 Perform SR 3.8.1.1 for OPERABLE required offsite circuit(s).

AND B.2 Declare required feature(s), supported by the inoperable DG, inoperable when the redundant required feature(s) are inoperable.

AND B.3.1 Determine OPERABLE DG(s) are not inoperable due to common cause failure.

OR B.3.2 Perform SR 3.8.1.2 for OPERABLE DG(s).

AND B.4 Restore required DG to OPERABLE status.

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from discovery of Condition B concurrent with inoperability of redundant required feature(s) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 24 hours 7 days*

(continued)

  • Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, the 7 day Completion Time is extended to 14 days. During the extended period, the compensatory actions listed in Attachment 4 of letter RS-23-128 dated December 15, 2023, shall be implemented. If SBO DG-1 becomes unavailable at any time during the extended period, the Required Action is to restore SBO DG-1 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or enter Condition F.

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-6 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS

NOTES -----------------------------------

1.

SR 3.8.1.1 through SR 3.8.1.20 are applicable only to the given unit's AC electrical power sources.

2.

SR 3.8.1.21 is applicable to the opposite unit's AC electrical power sources.

SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power availability for each required offsite circuit.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.2

NOTES-------------------

1.

All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.

2.

A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.

When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.8 must be met.

3.

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

4.

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR 3.8.1.2 for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

(continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-7 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.2 Verify each DG starts from standby (continued) conditions and achieves steady state voltage 3952 V and 4368 V and frequency 58.8 Hz and 61.2 Hz.

In accordance with the Surveillance 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 SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.8.

5.

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

6.

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR 3.8.1.3 for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

Verify each DG is synchronized and loaded and operates for 60 minutes at a load 2340 kW and 2600 kW.

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-8 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.4

NOTE--------------------

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR 3.8.1.4 for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

Verify each day tank contains 205 gal of fuel oil and each bulk fuel storage tank contains 10,000 gal of fuel oil.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.5

NOTE--------------------

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR 3.8.1.5 for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

Remove accumulated water from each day tank.

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-9 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.6

NOTE--------------------

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR 3.8.1.6 for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

Verify each fuel oil transfer pump operates to automatically transfer fuel oil from the storage tank to the day tank.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.7 Check for and remove accumulated water from each bulk storage tank.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.8

NOTES-------------------

1.

All DG starts may be preceded by an engine prelube period.

2.

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG starts from standby condition and achieves:

a.

In 13 seconds, voltage 3952 V and frequency 58.8 Hz; and

b.

Steady state voltage 3952 V and 4368 V and frequency 58.8 Hz and 61.2 Hz.

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-10 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.9 Verify manual transfer of unit power supply from the normal offsite circuit to the alternate offsite circuit.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.10

NOTE--------------------

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG rejects a load greater than or equal to its associated single largest post-accident load, and:

a.

Following load rejection, the frequency is 66.73 Hz;

b.

Within 3 seconds following load rejection, the voltage is 3952 V and 4368 V; and

c.

Within 4 seconds following load rejection, the frequency is 58.8 Hz and 61.2 Hz.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.11

NOTES--------------------

1.

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

2.

Momentary transients outside the voltage limit do not invalidate this test.

Verify each DG does not trip and voltage is maintained 5000 V during and following a load rejection of 2340 kW and 2600 kW.

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-11 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.12

NOTE--------------------

All DG starts may be preceded by an engine prelube period.

Verify on an actual or simulated loss of offsite power signal:

a.

De-energization of emergency buses;

b.

Load shedding from emergency buses; and

c.

DG auto-starts from standby condition and:

1. energizes permanently connected loads in 13 seconds,
2. maintains steady state voltage 3952 V and 4368 V,
3. maintains steady state frequency 58.8 Hz and 61.2 Hz, and
4. supplies permanently connected loads for 5 minutes.

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-12 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.13

NOTE--------------------

All DG starts may be preceded by an engine prelube period.

Verify on an actual or simulated Emergency Core Cooling System (ECCS) initiation signal each DG auto-starts from standby condition and:

a.

In 13 seconds after auto-start, achieves voltage 3952 V and frequency 58.8 Hz;

b.

Achieves steady state voltage 3952 V and 4368 V and frequency 58.8 Hz and 61.2 Hz; and

c.

Operates for 5 minutes.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.14 Verify each DG's automatic trips are bypassed on actual or simulated loss of voltage signal on the emergency bus concurrent with an actual or simulated ECCS initiation signal except:

a.

Engine overspeed; and

b.

Generator differential current.

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-13 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.15

NOTES-------------------

1.

Momentary transients outside the load range and power factor limit do not invalidate this test.

2.

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.

3.

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG operating within the power factor limit operates for 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s:

a.

For 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded 2730 kW and 2860 kW; and

b.

For the remaining hours of the test loaded 2340 kW and 2600 kW.

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-14 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.16

NOTES-------------------

1.

This Surveillance shall be performed within 5 minutes of shutting down the DG after the DG has operated 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded 2340 kW.

Momentary transients below the load limit do not invalidate this test.

2.

All DG starts may be preceded by an engine prelube period.

3.

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG starts and achieves:

a.

In 13 seconds, voltage 3952 and frequency 58.8 Hz; and

b.

Steady state voltage 3952 V and 4368 V and frequency 58.8 Hz and 61.2 Hz.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.17 Verify each DG:

a.

Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;

b.

Transfers loads to offsite power source; and

c.

Returns to ready-to-load operation.

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-15 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.18 Verify interval between each sequenced load block is 90% of the design interval for each load sequence time delay relay.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.19

NOTE--------------------

All DG starts may be preceded by an engine prelube period.

Verify, on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ECCS initiation signal:

a.

De-energization of emergency buses;

b.

Load shedding from emergency buses; and

c.

DG auto-starts from standby condition and:

1.

energizes permanently connected loads in 13 seconds,

2.

energizes auto-connected emergency loads including through time delay relays, where applicable,

3.

maintains steady state voltage 3952 V and 4368 V,

4.

maintains steady state frequency 58.8 Hz and 61.2 Hz, and

5.

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

In accordance with the Surveillance Frequency Control Program (continued)

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-16 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.20

NOTE--------------------

All DG starts may be preceded by an engine prelube period.

Verify, when started simultaneously from standby condition, each DG achieves, in 13 seconds, voltage 3952 V and frequency 58.8 Hz.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.21

NOTES-------------------

1.

When the opposite unit is in MODE 4 or 5, or moving recently irradiated fuel assemblies in secondary containment, the following opposite unit SRs are not required to be performed: SR 3.8.1.3, SR 3.8.1.10 through SR 3.8.1.12, and SR 3.8.1.14 through SR 3.8.1.17.

2.

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR 3.8.1.21 for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

For required opposite unit AC electrical power sources, the SRs of the opposite unit's Specification 3.8.1, except SR 3.8.1.9, SR 3.8.1.13, SR 3.8.1.18, SR 3.8.1.19, and SR 3.8.1.20, are applicable.

In accordance with applicable SRs

Diesel Fuel Oil and Starting Air 3.8.3 Quad Cities 1 and 2 3.8.3-2 Amendment No. 298/294 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and associated Completion Time of Condition A, B, or C not met.

OR One or more DGs with stored diesel fuel oil or starting air subsystem not within limits for reasons other than Condition A, B, or C.

D.1 Declare associated DG inoperable.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.3.1

NOTE-------------------

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR 3.8.3.1 for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

Verify fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of, the Diesel Fuel Oil Testing Program.

In accordance with the Diesel Fuel Oil Testing Program (continued)

Diesel Fuel Oil and Starting Air 3.8.3 Quad Cities 1 and 2 3.8.3-3 Amendment No. 298/294 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.3.2

NOTE-------------------

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR 3.8.3.2 for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

Verify each required DG air start receiver pressure is 230 psig.

In accordance with the Surveillance Frequency Control Program

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 298 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-29 AND AMENDMENT NO. 294 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-30 CONSTELLATION ENERGY GENERATION, LLC AND MIDAMERICAN ENERGY COMPANY QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 DOCKET NOS. 50-254 AND 50-265

1.0 INTRODUCTION

By letter to the U.S. Nuclear Regulatory Commission (NRC, the Commission) dated December 13, 2023 (Agencywide Documents Access and Management System (ADAMS)

Accession No. ML23347A217), as supplemented by letter dated December 15, 2023 (ML23349A033), Constellation Generation Company, LLC (the licensee) submitted a license amendment request (LAR) that proposed changes to the technical specifications (TSs) for the Quad Cities Nuclear Power Station (Quad Cities), Units 1 and 2. In its application, the licensee requested that the NRC process the proposed amendment on an emergency basis. The proposed changes would revise the Quad Cities TS 3.8.1, AC [alternating current] Sources -

Operating, to provide a one-time extension of the completion time (CT) for required action B.4 from 7 days to 14 days. The LAR also proposed to suspend performance of specified surveillance requirements (SRs) for Quad Cities, Unit 2 and 1/2 emergency diesel generators (EDGs) during the extended period.

2.0 REGULATORY EVALUATION

2.1

System Description

The LAR stated that the Quad Cities, Units 1 and 2, onsite AC power system consists of two main generators, two main step-up transformers, two reserve auxiliary transformers, distribution buses, three standby emergency DGs, and 2 standby station blackout (SBO) DGs. The unit Class 1E AC Electrical Power Distribution System AC sources consist of the offsite power sources and the onsite standby power sources (Quad Cities, Unit 1, emergency DG (EDG 1),

Quad Cities, Unit 2, emergency DG (EDG 2) and the common emergency DG (EDG 1/2)). As stated in Updated Final Safety Analysis Report (UFSAR) Section 3.1.7.3, Criterion 39 -

Emergency Power for ESF [engineered safety feature] (ML22042B307), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the ESF systems.

The LAR states that the Class 1E unit AC distribution system is, for the most part, divided into redundant load groups (Divisions 1 and 2), so loss of any one group does not prevent the minimum safety functions from being performed. The exception is that the opposite units AC Electrical Power Distribution System also powers shared loads.

The LAR states that offsite power is supplied to the 345 kilovolt (kV) switchyard from the transmission network by five transmission lines. From the 345 kV switchyard, one qualified electrically and physically separated circuit normally provides AC power to 4160 volt (V)

Essential Service System (ESS) bus 13-1 to supply the Division 1 loads of Quad Cities, Unit 1.

From the same switchyard, another qualified, electrically and physically separated circuit normally provides AC power to 4160 V ESS bus 23-1 to supply the Division 1 loads of Quad Cities, Unit 2. Another circuit, which is normally supplied by the Quad Cities, Unit 1, main generator, is normally aligned to supply the Quad Cities, Unit 1, Division 2 4160 V ESS bus 14-1. Finally, another circuit which is normally supplied by the Quad Cities, Unit 2, main generator, is normally aligned to supply the Quad Cities, Unit 2, Division 2 4160 V ESS bus 24-

1.

The LAR states that the onsite standby power source for 4160 V ESS buses 13-1, 14-1, 23-1, and 24-1 consists of three EDGs. EDG 1 and EDG 2 are dedicated to ESS buses 14-1 and 24-1, respectively. EDG 1/2 is a shared power source and can supply either Quad Cities, Unit 1, ESS bus 13-1 or Quad Cities, Unit 2, ESS bus 23-1. An EDG starts automatically on a loss-of-coolant accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) or on an ESS bus degraded voltage or undervoltage signal.

The LAR further states that after the EDG has started, it automatically ties to its respective bus after offsite power is tripped and certain permissives are met as a consequence of ESS bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The EDGs also start and operate in the standby mode without tying to the ESS bus on a LOCA signal alone. In the event of a LOCA on a unit, EDG 1/2 will start and supply the unit (bus 13-1 or 23-1) experiencing the accident if no offsite power is available. This is accomplished by using the accident signal to prevent the EDG 1/2 output breaker from closing on the non-accident unit.

Following the trip of offsite power, buses 13-1, 14-1, 23-1, and 24-1 are automatically disconnected from their normal supply and all nonessential loads are disconnected from the ESS bus except the 480 V ESS bus. When the EDG is tied to the ESS bus, loads are then sequentially connected to its respective ESS bus, if a LOCA signal is present, by the sequencing logic. The sequencing logic controls the starting signals to motor breakers to prevent overloading the EDG.

2.2 Description of Requested Changes Due to an unexpected failure of EDG 1 during a monthly test on December 11, 2023, at 1056 central standard time (CST), the licensee requested a CT extension to complete the repairs.

The LAR stated that the proposed change would revise TS 3.8.1 to provide a one-time extension of the completion time for required action B.4 from 7 days to 30 days. The supplement provided by letter dated December 15, 2023, revised the request to extend the CT from 7 days to 14 days. The licensee stated that the extension would provide sufficient time to complete repairs to the EDG 1 and avoid an unnecessary shutdown of both units without a commensurate benefit in nuclear safety. The change to TS 3.8.1 required action B.4 would add a footnote to the 7-day CT that states:

  • Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, the 7 day Completion Time is extended to 14 days. During the extended period, the compensatory actions listed in Attachment 4 of letter RS-23-128, dated December 15, 2023, shall be implemented. If SBO DG-1 becomes unavailable at any time during the extended period, the Required Action is to restore SBO DG-1 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or enter Condition F.

The LAR also requested to suspend several monthly SRs related to EDG performance and diesel fuel oil for EDG 2 and EDG 1/2 during the extended period that EDG 1 is inoperable. The licensee proposed to add a note to each specified SR that states:

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, performance of SR [ ] for DGs 2 and 1/2 may be suspended. Past due surveillances will be completed within 7 days of restoration of DG 1 operability or January 1, 2024, whichever occurs first.

The relevant SRs which support diesel operability in Limiting Conditions for Operation (LCO) 3.8.1 and LCO 3.8.3, Diesel Fuel Oil and Starting Air, are: SRs 3.8.1.2 through 3.8.1.6, 3.8.1.21, 3.8.3.1, and 3.8.3.2.

2.3 Regulatory Requirements and Guidance Title 10 of the Code of Federal Regulations (10 CFR) 50.36, Technical specifications, provides the regulatory requirements for the content of the TS. It requires, in part, that a summary statement of the bases for such specifications shall be included by applicants for a license authorizing operation of a production or utilization facility. Specifically, 10 CFR 50.36(c) requires that TS include items in specific categories related to station operation. These categories include: (1) safety limits, limiting safety system settings, and limiting control settings; (2) LCOs; (3) SRs; (4) design features; and (5) administrative controls.

The regulation 10 CFR 50.36(c)(2)(i), Limiting conditions for operation, states, in part, that TS will include LCOs, which are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

The regulation in 10 CFR 50.36(c)(3), Surveillance Requirements, 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.

The regulation in 10 CFR 50.63, Loss of all alternating current power, paragraph (a),

Requirements, requires that each light water-cooled nuclear power plant licensed to operate be able to withstand for a specified duration and recover from an SBO.

The construction permits for Quad Cities, Units 1 and 2 predate the formal issuance of the current Appendix A, General Design Criteria (GDC), to 10 CFR Part 50. During the construction permit licensing process, Units 1 and 2 were evaluated against the General Design Criteria for Nuclear Power Plant Construction Permits, draft for comment, 32 FR 10214 (July 11, 1967) (1967 Draft GDC). The design bases of each Quad Cities unit were reevaluated at the time of initial Final Safety Analysis Report preparation against the draft GDC current at the time of operating license application.

As stated in Section 3.1, Conformance with NRC General Design Criteria, of the UFSAR (based on the understanding of the proposed criteria current at the time of operating license application), Quad Cities, Units 1 and 2, conforms with the Atomic Energy Commission GDC for Nuclear Power Plant Construction Permits. As the GDC were finalized, the requirements were placed in Appendix A, General Design Criteria for Nuclear Power Plants, to 10 CFR Part 50, Domestic Licensing of Production and Utilization Facilities. The 1967 Draft GDC, Criterion 24, Emergency Power for Protection Systems (Category B), requires that in the event of loss of all offsite power, sufficient alternate sources of power shall be provided to permit the required functioning of reactor protection systems. The 1967 Draft GDC, Criterion 39, Emergency Power for Engineered Safety Features (Category A), requires the alternate power systems, both onsite and offsite, to have adequate independence, redundancy, capacity, and testability to perform the functioning of the engineered safety features, assuming a single failure in each system.

Regulatory Guide (RG) 1.177, Revision 2, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications (ML20164A034), provides an approach that is acceptable to the NRC staff for developing risk-informed applications for changes to completion times and surveillance frequencies of plant TSs.

NUREG-0800, Branch Technical Position (BTP) 8-8, Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions (ML113640138), provides guidance, from a deterministic perspective, for reviewing an EDG outage time extension request up to 14 days. The NRC staff used the guidance in BTP 8-8 to review the proposed change.

NRC Generic Letter (GL) 80-30, Clarification of the Term 'Operable' as it Applies to Single Failure Criterion for Safety Systems Required by Technical Specifications, states that When required redundancy is not maintained, either due to equipment failure or maintenance outage, action is required, within a specified time, to change the operating mode of the plant to place it in a safe condition. The specified time to take action, usually called the equipment out-of-service time, is a temporary relaxation of the single failure criterion, which, consistent with overall system reliability considerations, provides a limited time to fix equipment or otherwise make it OPERABLE. If equipment can be returned to OPERABLE status within the specified time, plant shutdown is not required.

3.0 TECHNICAL EVALUATION

3.1 Deterministic Evaluation The NRC staffs deterministic evaluation of the proposed change considered various potential plant conditions that could be encountered while exercising the one-time CT extension. The NRC staff also considered the available redundant or diverse means to respond to various plant conditions. The NRC staff reviewed information pertaining to the electrical power systems in the application, the UFSAR, applicable TS LCO and TS Bases to verify the capability of the affected electrical power systems to perform their safety functions (assuming no additional failures of electrical components) is maintained. The review includes the capacity of the remaining and alternate power sources to verify whether these power sources are capable of providing power to the safety buses when one of the required power sources per TS LCO is declared inoperable.

The NRC staff considered supplemental electrical power sources (not necessarily required by the LCOs and may not be safety related) that are available at Quad Cities, Units 1 and 2, and can provide defense-in-depth function in case of an inoperable electrical power source.

NUREG-0800, BTP 8-8 provides guidance, from a deterministic perspective, for reviewing completion time extension request for AC power source. The NRC staffs evaluation of the proposed change that includes the BTP 8-8 defense-in-depth aspects is provided below.

3.1.1 Evaluation of Impacts on Onsite Power Sources As described in the LAR, the onsite standby power source for 4160 V ESS buses 13-1, 14-1, 23-1, and 24-1 consists of three EDGs. EDG 1 and EDG 2 are dedicated to ESS buses 14-1 and 24-1, respectively. EDG 2 can also be manually connected (cross-tied) to bus 14-1 [via Bus 24-1 per UFSAR Figure 8.3-1] (ML21300A266). EDG 1/2 is a shared power source and can supply either Unit 1 ESS bus 13-1 or Unit 2 ESS bus 23-1. According to the UFSAR, Section 8.3, Onsite Power Systems, each emergency DG has a continuous rating of 2600 kilo-Watts (kW). The plant also has two SBO DGs each with a continuous rating of 4350 kW.

The NRC staffs evaluation of the proposed change considered various potential plant conditions that could be encountered while exercising the one-time CT extension, including a loss-of-offsite power (LOOP) as assumed by safety analysis. In accordance with GL 80-30, additional single failures of plant components are not necessary for evaluating accidents when operating in a particular TS LCO condition for a limited time.

In order to evaluate whether Quad Cities, Unit 1, can be safely brought to cold shutdown in accordance with BTP 8-8 in case of SBO, the NRC staff requested additional information (RAI #1) for the scenario of a LOOP, EDG 1 inoperable, EDG 1/2 fails to connect to bus 14-1 (resulting in SBO of Quad Cities, Unit 1). In the letter dated December 15, 2023, the licensee stated, in part, that the preference for energizing Bus 14-1 would be to use the cross-tie from Bus 24-1 which could be fed from unit auxiliary transformer (T21), reserve auxiliary transformer (T22), EDG 2, or Unit 2 SBO DG. If the cross-tie to Bus 24-1 were not available, operators would proceed to energize Bus 14-1 with the Unit 1 SBO DG. The NRC staff notes that during the above scenario, Bus 14-1 can be powered from Bus 24-2 or the Unit 1 SBO DG. The NRC staff finds that during this scenario, Quad Cities, Unit 1, will have adequate power to bring the unit to cold shutdown in case of extended LOOP and thus follows BTP 8-8.

3.1.2 Evaluation of Impacts on the Opposite Unit Equipment TS LCO 3.8.1 states, in part:

The following AC electrical power sources shall be OPERABLE:

d. The opposite units DG capable of supporting the equipment required to be OPERABLE by LCO 3.6.4.3, LCO 3.7.4 (Unit 2 only), and LCO 3.7.5 (Unit 2 only).

In response to the NRC staff request (RAI #3) related to the impact of the EDG 1 inoperability on the Unit 2 equipment required to be operable by LCO 3.6.4.3, in the letter dated December 15, 2023, the licensee stated, in part, that the Standby Gas Treatment (SGT) system consists of two fully redundant subsystems (A and B) that are shared between Units 1 and 2.

LCO 3.6.4.3, addresses operability of A and B SGT. A SGT is powered from Unit 2, Division II, Bus 29 (i.e., the Unit 2 EDG during a LOOP event). B SGT is powered from Unit 1, Division II (i.e., the Unit 1 EDG during a LOOP event).

The letter dated December 15, 2023, further states that start of B SGT would be delayed due to manual initiation of the Unit 1 SBO DG supplying power to Bus 14-1, which will take approximately 4 minutes and 32 seconds. The 'A' SBGT [SGT] train would be expected to have auto-started on low flow in this time frame if power is available to motor control center (MCC) 29-4 to support this key safety function. The licensee concludes that since A SGT is independent of B SGT and the EDG 1, it will meet the post-accident requirements for SGT.

Regarding the impact of the EDG 1 inoperable on the Unit 2 equipment required to be operable by LCOs 3.7.4 and 3.7.5, in the letter dated December 15, 2023, the licensee stated that the Control Room Emergency Ventilation (CREV) System and the CREV Air Conditioning System are powered from Unit 1, Division I bus (Bus 18). Ordinarily, the EDG 1 can supply power to Bus 18 via the Bus 18 and 19 cross-tie. In addition, EDG 1/2 can promptly supply power to Bus 18. Alternatively, the Unit 1 SBO DG can also supply Bus 18 once it is loaded to Bus 14-1, Bus 19, and with the Bus 18 and 19 cross-tie closed.

Based on the information the licensee provided, the NRC staff finds that during the proposed one-time CT extension, the impact of the EDG 1 inoperable on the Unit 2 equipment required to be operable by the TS is acceptable because the approximately 4.5 minute delay to load the Unit 1 SBO DG to Bus 14-1 on the systems capability to perform their functions is minimal.

3.1.3 Evaluation of Alternate Power Sources As stated in the LAR, the SBO system is a non-class 1E, independent source of additional onsite emergency AC power. Each generator is connectable, but not normally connected to the safe shutdown equipment on one nuclear unit but can also be connected to the opposite unit via the safety-related 4kV cross-ties.

Regarding the SBO DG load capacity related to LOOP/LOCA load requirement, UFSAR Section 8.3.1.9.3, System Loads, states, in part, that the worst-case divisional load requirement was used as the design basis for the minimum generator capacity. This capacity envelopes the load requirements for a LOOP or LOCA event. Additional capacity to reduce the need for operator manual load-shedding and contingency margin of 10 percent was added to this minimum capacity. All loading consists of manually connected loads.

Regarding the ability to make the SBO DG available, UFSAR Section 8.3.1.9, Station Blackout Diesel Generator System, states, in part, that in response to SBO rule, the alternate AC (AAC) system consists of a standby diesel generator, available within one hour of the onset of an SBO event, controllable from the main control room, and connectable to all safety buses. In the letter dated December 15, 2023, the licensee further stated (in response to RAI #1) that the expected performance time for starting the Unit 1 SBO DG and providing power to Bus 14-1 is 4 minutes, 32 seconds. In the event of a failure of remote functionality from the Main Control Room, local start of the Unit 1 SBO DG is assumed to be dispatched within 10 minutes, with an expected execution time of 18.7 minutes, leading to a total time of 28.7 minutes.

As for the compensatory action related to the SBO DG, in the letter dated December 15, 2023, the licensee stated (in response to RAI #4), in part, that rounds on the SBO will be changed to shiftly (8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) during the extended CT period.

Based on the information from the UFSAR, the LAR, and the responses to the NRC staff RAI provided in the letter dated December 15, 2023, the NRC staff finds that with EDG 1 inoperable during the proposed one-time extended CT period, the SBO DGs can serve as alternate power source because (a) this alternate power source has the sufficient capacity to supply the power required to maintain both units in a safe shutdown condition, (b) the SBO DGs can be made available within one hour, as recommended by BTP 8-8, and (c) the availability of the SBO DGs will be verified every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> during the one-time extended CT period.

3.1.4 Evaluation of Compensatory Actions In the letter dated December 15, 2023, the licensee provided the compensatory actions to help ensure the availability of AC power and the equipment impacted by the inoperable EDG during the proposed CT extension. The NRC staff notes that these compensatory measures include the following:

Limiting maintenance activities on electrical equipment including the EDGs, SBO DGs, and switchyard.

The equipment impacted by the proposed change will be protected per the Protected Equipment Program.

The grid reliability will be monitored.

The availability of the AAC will be monitored and verified.

The NRC staff finds that the proposed compensatory actions are adequate to help ensure the availability of AC power sources and the equipment for safe shutdown of the plant. The staff also finds that these compensatory actions are consistent with guidance in BTP 8-8.

3.1.5 Evaluation of Surveillance Requirements Suspension In the LAR, the licensee proposed to temporarily suspend the performance of several monthly SRs for the remaining two of three operable EDGs. In LAR section 2.2 to attachment 1, the licensee used an example to explain how scheduled testing of EDG 2 and EDG 1/2 could exceed their monthly frequency during the period that EDG 1 is inoperable. An EDG under testing is typically required to be declared inoperable and testing could take several hours. With EDG 1 currently inoperable and either EDG 2 or EDG 1/2 undergoing monthly SR, test performance would require entering TS 3.8.1 condition E for [t]wo required DGs inoperable.

Condition E would require restoration of one EDG within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Further, if condition E were not met, TS 3.8.1 condition F would require both units to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The licensee stated that testing of the two operable EDGs would result in an unnecessary shutdown without equivalent benefit in nuclear safety. To support the proposed extended CT for TS 3.8.1 required action B.4, the licensee would add a note to each of the specified SRs that would allow suspension of the requirements until EDG 1 is returned to operable status. The note also would indicate that the past due SR will be completed within 7 days of restoration of EDG 1 operability or January 1, 2024, whichever occurs first.

The NRC staff reviewed the Quad Cities, Units 1 and 2, TS, TS bases, and the LAR, as supplemented, for the proposed changes to the relevant SRs in LCO 3.8.1 and LCO 3.8.3. The requested one-time extension of the CT for TS 3.8.1 required action B.4 would add 7 days to the current 7-day CT for a maximum of 14 days (i.e., until December 25, 2023, at 1056 CST).

During the period EDG 1 is inoperable, Quad Cities, Unit 1 and Unit 2, will be supported by the two operable DGs. Removing either one from service for testing would put both units in a vulnerable condition by severely reducing the redundancy in the onsite AC power system. As stated in the LAR, each SR that the licensee proposed to suspend has a frequency of 31 days (monthly). Per the requirements in Quad Cities, Units 1 and 2, SR 3.0.2, SRs are to be performed within 1.25 times their frequency, which adds approximately one week to a monthly SR. Additionally, SR 3.0.2 requires that any exceptions to the 1.25 frequency would be stated in the individual specifications. The licensee proposed to add an exception note to each specified SR to suspend monthly testing during the repair of EDG 1.

The NRC staff finds that the proposed change to temporarily suspend the performance of SRs 3.8.1.2 through 3.8.1.6, 3.8.1.21, 3.8.3.1, and 3.8.3.2 for EDG 2 and the EDG 1/2 is acceptable. The staff determined this meets 10 CR 50.36(c)(2)(i) because the temporary suspension of the SRs during repair of EDG 1 would support both Quad Cities units by (1) maintaining minimum equipment available to perform the safety function to provide onsite AC power for safe shutdown and accident mitigation, and (2) rather than testing, keeping the operable EDGs in a standby state during the EDG 1 repair activities would provide defense in depth. In addition, though the requirements will be suspended, the staff finds the SRs remain technically unchanged and the suspension is only temporarythe licensee will perform the SRs within a reasonably short time after EDG 1 is restored to operability; therefore, the SRs will continue to meet 10 CFR 50.36(c)(3).

3.1.6 Deterministic Evaluation Conclusion The NRC staff reviewed the proposed change to Quad Cities, Units 1 and 2, TS 3.8.1. The change would revise TS 3.8.1 by allowing a temporary, one-time extension of Required Action B.4 CT. Based on the above evaluations, the NRC staff finds that during the extended CT periods, while the redundancy of the onsite AC power source is reduced, the minimum capacity and capability of the electrical power system to provide power to the safety-related systems is maintained (assuming no additional failures of electrical components). The NRC staff finds that the impact of the EDG 1 inoperability on the Unit 2 equipment required to be operable by the TS is minimal. The staff also finds that the SBO DG is an adequate alternate power source for the onsite AC power source during the proposed extended CT periods. In addition, the staff finds that the proposed compensatory measures are adequate to help ensure the availability of AC power sources and the equipment for safe shutdown of the plant during the one-time CT extension of EDG 1. Regarding the temporary suspension of monthly SRs for the operable EDGs, the staff finds that the proposed change is acceptable and supports the defense in depth of the safety function of the onsite AC power system during the temporary suspension period.

The NRC staff determined that the proposed change continues to meet the purpose of the electrical power systems design concerning availability, capacity, and capability on a temporary basis. The proposed change is consistent with 10 CFR 50.36(c)(2) because the lowest functional capability or performance levels of equipment required for safety is maintained. The proposed change is consistent with 10 CFR 50.36(c)(3) because though monthly SRs for the operable EDGs would be suspended, they are technically unchanged, will continue to assure that limited conditions for operation will be met, and will be delayed for a reasonably short time.

The proposed change is also consistent with guidance in BTP 8-8. Therefore, the NRC staff concludes that the proposed changes are acceptable.

3.2 Risk Insights In the subject LAR, the licensee requested a one-time, deterministic risk-informed emergency license amendment to extend the current Completion Time of TS 3.8.1, Required Action B.4, to avoid an unnecessary shutdown of Quad Cities, Units 1 and 2, without a commensurate benefit in nuclear safety. Therefore, it is not a risk-informed LAR, and a detailed risk evaluation was not submitted for the purpose of making a regulatory decision.

While this is not a risk-informed LAR, the licensee provided risk insights related to the proposed TS CT change. To aid in the deterministic review of the proposed one-time change, the staff considered the licensee-provided risk insights utilizing guidance described in Section 2.3, Evaluation of Risk Impact, of RG 1.177. RG 1.177 describes a three-tier approach to evaluation risk-insights for changes to TS CTs, summarized below as applicable to this LAR:

Tier 1 considers two aspects of the impact of the TS CT change: the acceptability of the plant-specific probabilistic risk assessment (PRA) and the PRA insights and results.

Tier 2 identifies potentially high-risk configurations that could exist if additional equipment is taken out of service or involved in system or equipment testing concurrent with the period of the TS CT change. The object of this part of the evaluation is to ensure appropriate restrictions on the dominant risk-significant configurations associated with the change are in place. In addition, compensatory measures that can mitigate any corresponding increase in risk (e.g., backup equipment, increased SF [surveillance frequencies], or upgraded procedures and training) should be identified and evaluated.

Tier 3 establishes a risk-informed plant configuration control program. If the Tier 2 assessment demonstrates that there are no risk-significant configurations involving the subject equipment, the application of Tier 3 to the proposed CT may not be necessary.

Tier 1 Evaluation:

The NRC has previously reviewed the technical adequacy of the Quad Cities PRA models for Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (ML102920260). The PRA models were previously reviewed to the extent needed to support previous risk-informed LARs, and are therefore determined to be acceptable for the review of the subject LAR, which is deterministic with risk insights. The NRC staff also performed an independent assessment of the proposed one-time TS CT change using the NRCs Quad Cities, Units 1 and 2, Standardized Plant Analysis Risk (SPAR) Models. The incremental conditional core damage probability (ICCDP) calculated by the SPAR model was evaluated against RG 1.177 Section 2.4, Acceptance Guidelines for Technical Specification Changes, for one-time TS CT changes, and was found to fall within the range where the one-time TS CT change is acceptable with effective compensatory measures implemented to reduce the sources of increased risk.

Tier 2 Evaluation:

The results of the SPAR model identified potentially high-risk configurations or events which could occur during the period of the proposed TS CT, and were the greatest contributors to ICCDP. Several potential high-risk configurations and events were identified:

Unavailability of power systems associated with the inoperability of EDG 1, i.e.,

unavailability of EDG 1/2 and associated non-safety related SBO DGs.

Common Cause failure of the diesel generators.

Losses of offsite AC power resulting from high-risk configurations or activities in the switchyard, or from external hazards such as seismic or weather events.

Loss of onsite DC power from battery failure or depletion.

Failure of operators to respond appropriately to unavailability of equipment or loss of AC power.

The subject LAR provided a description of compensatory measures that would be implemented during the one-time TS CT change to reduce the risk impact of the one-time TS CT change. By letter December 14, 2023, NRC issued RAIs (ML23349A036). In the RAIs, the NRC staff requested a list of specific compensatory measures, more information describing how the plant systems will respond to external hazards that could impact loss of AC power, and a sensitivity study calculating the impact of common cause failure of the diesel generators.

By letter dated December 15, 2023, the licensee provided a response to the request. of the response is a comprehensive list of compensatory measures to address the contributors to ICCDP described above. The compensatory measures include actions such as management of any emergent work in accordance with 10 CFR 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants, paragraph (a)(4),

implementing the Protected Equipment Program to protect vital direct current and AC buses, and performing job briefs according to cited plant procedures. The licensee will implement risk management actions for each configuration described in its Online Fire Risk Management Program. The licensee will also pre-stage a single FLEX diesel generator and increase operator rounds to ensure availability of the SBO generators. The response to the RAIs also provided a description of the effect of external hazards on the plant, which the staff finds acceptable. In addition, the licensee provided a sensitivity study calculating common cause failure. The resulting ICCDP was found to fall within the acceptable range according to RG 1.77.

NRC staff reviewed the list of compensatory actions in Attachment 4 and other responses to the RAI and determined that these measures would be effective in reducing the sources of increased risk. The information provided in the LAR and the supplement response to the RAI are sufficient to meet the Tier 1 and Tier 2 criteria described in RG 1.177. Therefore, a Tier 3 evaluation is determined not to be necessary.

The licensee-provided risk insights and the NRC SPAR model insights and results both supported the engineering conclusions associated with the appropriateness of the licensees proposed compensatory actions. The currently available risk insights and results did not challenge the engineering conclusions that the proposed change maintains defense-in-depth.

Therefore, from a risk-insight perspective, the NRC staff finds the proposed one-time change to the TS CT to be acceptable.

3.3 Technical Evaluation Summary The NRC staff has reviewed the proposed change to TS 3.8.1 required action B.4 to extend the completion time for an inoperable EDG 1 from the current 7 days to 14 days and to suspend SRs EDG 2 and EDG 1/2 for the current period of inoperability of EDG 1. Based on the above evaluation, the NRC staff concludes that the proposed change satisfies all of the applicable regulatory requirements identified in Section 2.3 and will continue to provide reasonable assurance of adequate protection to public health and safety 4.0 EMERGENCY SITUATION

=

Background===

The NRCs regulations in 10 CFR 50.91(a)(5) state that where the NRC finds that an emergency situation exists, in that failure to act in a timely way would result in derating or shutdown of a nuclear power plant, or in prevention of either resumption of operation or of increase in power output up to the plants licensed power level, the NRC may issue a license amendment involving no significant hazards consideration without prior notice and opportunity for a hearing or for public comment. In such a situation, the NRC will publish a notice of issuance under 10 CFR 2.106, providing for opportunity for a hearing and for public comment after issuance.

As discussed in the application dated December 13, 2023, the licensee requested that the proposed amendment be processed by the NRC on an emergency basis. The license amendment request stated that:

The Unit 1 DG was removed from service in support of the monthly load test surveillance on December 11, 2023, at 1056 CT. Due to the configuration and shared electrical distribution system at QCNPS [Quad Cities Nuclear Power Station], both units entered TS 3.8.1, Condition B (i.e., one DG inoperable). At 1205 hours0.0139 days <br />0.335 hours <br />0.00199 weeks <br />4.585025e-4 months <br /> CST an unplanned failure of the Unit 1 DG exciter resulted in an arc flash in the 2251-12 panel resulting in charring and cabinet door deflection. The DG was 43 minutes into a two-hour monthly load test when it tripped. Prior to the DG tripping, a momentary lowering voltage on safety related bus 14-1 resulted in an undervoltage trip of B Reactor Protection System (RPS). Reactor Building Ventilation isolated and Standby Gas Treatment (SBGT) automatically started.

Bus 14-1 did not trip. Both Units remain in TS 3.8.1 Condition B as a result of the exciter failure.

Maintenance activities continue in support of restoring the Unit 1 DG to an operable status but is not expected to be complete before the expiration of the current 7-day Completion Time. If the Unit 1 DG is not restored to operable status by 1056 hours0.0122 days <br />0.293 hours <br />0.00175 weeks <br />4.01808e-4 months <br /> on December 18, 2023, Condition F will be entered which requires being in MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (i.e., by 2256 hours0.0261 days <br />0.627 hours <br />0.00373 weeks <br />8.58408e-4 months <br /> on December 18, 2023).

NRC Staff Conclusion The NRC staff reviewed the licensees basis for processing the proposed amendment as an emergency amendment (as discussed above) and has determined that an emergency situation exists consistent with the provisions in 10 CFR 50.91(a)(5). Furthermore, the NRC staff determined that: (1) the licensee used its best efforts to make a timely application; (2) the licensee could not reasonably have avoided the situation; and (3) the licensee has not abused the provisions of 10 CFR 50.91(a)(5). Based on these findings, and the determination that the amendment involves no significant hazards consideration as discussed below, the NRC staff has determined that a valid need exists for issuance of the license amendment using the emergency provisions of 10 CFR 50.91(a)(5).

5.0 FINAL NO SIGNIFICANT HAZARDS CONSIDERATION

The NRCs regulation in 10 CFR 50.92(c) states that the NRC may make a final determination, under the procedures in 10 CFR 50.91, that a license amendment involves no significant hazards consideration if operation of the facility, in accordance with the 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.

An evaluation of the issue of no significant hazards consideration is presented below:

1.

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

Response: No The consequences of an evaluated accident are determined by the operability of plant systems designed to mitigate those consequences. The EDGs are backup power to components that mitigate the consequences of accidents. The proposed license amendment provides a deterministic one-time change to extend the CT for Required Action B.4 from 7 days to 14 days. This change has no impact on accident probabilities because the EDGs are not considered accident initiators. Similarly, the change does not significantly affect the capability of any SSC to mitigate the consequences of a previously evaluated accident. The proposed extension of the CT does not require any physical plant modifications. All planned work is aimed at restoring the inoperable EDG to an operable status, and suspending surveillances on the other two EDGs during the period of repair helps ensure those EDGs remain operable. Because no individual precursors of an accident are affected, the proposed amendment does not increase the probability of a previously analyzed event.

Therefore, the proposed changes do 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 Creation of the possibility of a new or different kind of accident requires creating one or more new accident precursors. The proposed license amendment provides a deterministic one-time change to extend the CT for Required Action B.4 from 7 days to 14 days. The proposed change does not involve a modification of the physical configuration of the plant (i.e., no new equipment will be installed, nor will the design of currently installed equipment be modified), create any new failure modes for existing equipment, or create any new limiting single failures.

Therefore, the proposed changes do 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 proposed license amendment provides a deterministic, risk-informed one-time change to extend the CT for Required Action B.4 from 7 days to 14 days and suspends testing of the Unit 2 and common (1/2) DGs per SRs during the proposed extended CT.

These changes do not impact any limiting safety setting or alter any safety limits.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above evaluation, the NRC staff concludes that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff has made a final determination that no significant hazards consideration is involved for the proposed amendment and that the amendment should be issued as allowed by the criteria contained in 10 CFR 50.91.

6.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Illinois State official was notified of the proposed issuance of the amendment on December 15, 2023. The State official had no comments.

7.0 ENVIRONMENTAL CONSIDERATION

The amendment changes the requirements with respect to installation or use of a facilitys components located within the restricted area as defined in 10 CFR Part 20 and a change to surveillance requirements. As indicated above, the NRC staff has determined that the amendment involves no significant hazards consideration. The NRC staff has also determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

8.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commissions 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.

Principal Contributors: April Pulvirenti, NRR Khoi Nguyen, NRR Khadijah West, NRR Date of Issuance: December 17, 2023

ML23349A162 OFFICE NRR/DORL/LPL3/PM NRR/DORL/LPL3/LA NRR/DEX/EEEB/BC NRR/DRA/APLA/BC NAME RKuntz ABaxter WMorton (VGoel for)

RPascarelli DATE 12/15/2023 12/15/2023 12/15/2023 12/16/2023 OFFICE NRR/DSS/STSB/BC (A)

OGC NLO NRR/DORL/LPL3/BC NRR/DORL/LPL3/PM NAME SMehta (A) (CAshley for) RWeisman JWhited (SWall for)

RKuntz DATE 12/15/2023 12/16/2023 12/17/2023 12/17/2023

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