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(CPNPP) - License Amendment Request Proposing Changes to Technical Specifications to Extend the Allowed Outage Time for an Inoperable Emergency Diesel Generator from 72 Hours to 14 Days
	ML23257A172
Person / Time
Site:	Comanche Peak
Issue date:	09/14/2023
From:	John Lloyd; Luminant, Vistra Operating Co. (VistraOpCo)
To:	; Office of Nuclear Reactor Regulation, Document Control Desk
References
	CP-202300293, TXX-23045
	Download: ML23257A172 (1)
	v • d • e

CP-202300293 TXX-23045 September 14, 2023 ATTN: Document Control Desk Ref 10 CFR 50.90 U. S. Nuclear Regulatory Commission 10 CFR 50.91 Washington, DC 20555-0001

Subject:

Comanche Peak Nuclear Power Plant (CPNPP)

Docket Nos. 50-445 and 50-446 License Amendment Request Proposing Changes to Technical Specifications to Extend the Allowed Outage Time for an Inoperable Emergency Diesel Generator from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 Days.

Dear Sir or Madam:

Pursuant to 10 CFR 50.90, Vistra Operations Company LLC (Vistra OpCo) is submitting a request for an amendment to the Technical Specifications for Comanche Peak Nuclear Power Plant Units 1 and 2 (CPNPP). The proposed amendment would modify the CPNPP Technical Specification Required Action 3.8.1.B.4 to extend the allowed outage time for an inoperable emergency diesel generator from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days.

The enclosure to this letter contains an evaluation of the proposed change. Attachment 1 of the enclosure includes a markup of the Technical Specifications. Attachment 2 of the enclosure includes a markup of the Technical Specifications Bases for information only. Attachment 3 of the enclosure provides relevant Figures for information only. Attachment 4 of the enclosure is a copy of the CPNPP work management Philosophy. Attachment 5 is a copy of the 14-day completion time entry preparatory measures.

Vistra OpCo concludes that the proposed change does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified. The CPNPP Station Operations Review Committee (SORC) has reviewed the proposed license amendment.

Vistra OpCo requests approval of the proposed license amendment within one year of completion of the NRC's acceptance review. The amendment will be implemented within 90 days after approval.

There are no new regulatory commitments made in this submittal.

In accordance with 10 CFR 50.91, a copy of this application, with attachments, is being provided to the designated State of Texas Official.

Should you have any questions, please contact Nic Boehmisch at (254) 897-5064 or nicholas.boehmisch@luminant.com.

Jay J. Lloyd Senior Director, Engineering & Regulatory Affairs Comanche Peak Nuclear Power Plant (Vistra Operations Company LLC)

P.O. Box 1002 6322 North FM 56 Glen Rose, TX 76043 T

254.897.5337

TXX-23045 Page 2 of 2 I state under penalty of perjury that the foregoing is true and correct.

Executed on September 14, 2023.

Sincerely, JayLloy

CDT)

Jay J. Lloyd

Enclosure:

Evaluation of the Proposed Change c (email) -

John Monninger, Region IV [John.Monninger@nrc.gov]

Dennis Galvin, NRR [Dennis.Galvin@nrc.gov]

John Ellegood, Senior Resident Inspector, CPNPP [John.Ellegood@nrc.gov]

Dominic Antonangeli, Resident Inspector, CPNPP [Dominic.Antonangeli@nrc.gov]

Mr. Robert Free [robert.free@dshs.state.tx.us]

Environmental Monitoring & Emergency Response Manager Texas Department of State Health Services Mail Code 1986 P. 0. Box 149347 Austin TX, 78714-9347

Enclosure to TXX-23045 Page 1 of 33 Evaluation of the Proposed Change

Subject:

License Amendment Request Proposing Changes to Technical Specifications to Extend the Allowed Outage Time for an Inoperable Emergency Diesel Generator from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 Days 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION 2.1 Standby AC Power System Design and Operation 2.2 Completion Time Change 2.3 Reason for TS 3.8.1 Proposed Change (14 Day DG CT) 2.4 Bases for TS 3.8.1 Proposed Change (14 Day DG CT) 2.5 AC Source Operability Requirements for Shared and Cross-Connectable Systems

3.0 TECHNICAL EVALUATION

3.1 CPNPP AC Power Systems Description 3.2 Grid Reliability 3.3 Station Blackout Capability 3.4 Alternate Power Diesel Generators (APDGs) 3.5 Fire Hazards 3.6 Training 3.7 Maintenance Rule Program (10 CFR 50.65) 3.8 Work Management 3.9 Engineering Considerations 3.10 Defense-In-Depth 3.11 Safety Margin 3.12 Deterministic Assessment of Proposed DG Completion Time Change 3.13 Risk Insights 3.14 Risk Assessment

Enclosure to TXX-23045 Page 2 of 33 3.15 Conclusion Regarding DG Completion Time Change 3.16 Evaluation of AC Source Operability Requirements for Shared Systems 3.17 Risk Informed Completion Time Front Stop

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements 4.2 Precedent 4.3 No Significant Hazards Consideration Determination 4.4 Conclusions

5.0 ENVIRONMENTAL CONSIDERATION

S

6.0 REFERENCES

ATTACHMENTS

1. Technical Specification Pages Technical Specification Markup Pages Technical Specification Revised Pages

2. Technical Specification Bases Pages (For Information Only)

Technical Specification Bases Markup Pages

3.

CPNPP System Figures (For Information Only)

Figure 1 - CPNPP Electrical Grid Connections Figure 2 - Component Cooling Water System Figure 3 - Component Cooling Water Safeguards Loops Figure 4 - Station Service Water System Figure 5 - Control Room Air Conditioning System Figure 6 - Primary Plant Ventilation System Supply Figure 7 - Primary Plant Ventilation System Exhaust Figure 8 - Uninterruptable Power Supply HVAC System

4.

CPNPP Work Management Philosophy (STI-604.02 Attachment 8.C)

5.

14-day Completion Time Entry

6.

Baseline Average Annual CDF/LERF

7.

ICCDP and ICLERP for 14-day Completion Time for one Emergency Diesel Generator Inoperable

Enclosure to TXX-23045 Page 3 of 33 1.0

SUMMARY

DESCRIPTION Pursuant to 10 CFR 50.90, Vistra Operations Company LLC (Vistra OpCo) is submitting a License Amendment Request proposing a change to Technical Specification (TS) 3.8.1, AC Sources -- Operating for CPNPP Units 1 and 2.

The LAR proposes to revise the Required Actions (RA) and Completion Time (CT) for an inoperable Emergency Diesel Generator (DG). This proposed change is based upon availability of a supplemental AC power source. Extending the CT requires that an alternate source of power be provided. This LAR utilizes deterministic assessments supported by risk insight to provide technical justification for the TS change and has been developed using the guidelines established in NUREG-0800, Branch Technical Position (BTP) 8-8, Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions.

The Safety Function Determination Program (SFDP), described in Technical Specification 5.5.15, ensures at least one train of shared or cross-connectable components has an operable emergency power supply. The systems at CPNPP which may be supplied from either unit are Component Cooling Water System (CCWS) through piping cross-connects, Station Service Water System (SSWS) through piping cross-connects, Control Room Emergency Filtration/Pressurization System (CREFS) through electrical diversity, Control Room Air Conditioning System (CRACS) through electrical diversity, Primary Plant Ventilation System (PPVS) - ESF Filtration Trains through electrical diversity, and Uninterruptable Power Supply (UPS)

HVAC System (UPS HVAC) through electrical diversity. In addition, the CPNPP TS definition of OPERABLE/OPERABILITY only requires normal or emergency power.

For the unaffected train, the normal and emergency power supply will be protected through normal work management processes. As a further defense-in-depth action, the Alternate Power Diesel Generators (APDG) for the affected unit are verified to be available including the ability to refuel during operation.

No changes to the CPNPP Final Safety Analysis Report (FSAR) are anticipated as a result of this License Amendment Request.

2.0 DETAILED DESCRIPTION 2.1 Standby AC Power System Design and Operation The standby AC Power System is an independent, onsite, automatically starting system designed to furnish reliable and adequate power for Class 1E loads to ensure safe plant shutdown and to maintain the plant in standby when the preferred and alternate off-site power sources are not available. Four independent diesel generator sets, two per unit, are provided.

Each diesel generator is driven by a single prime mover and is capable of sequentially starting and supplying power in response to a Design Basis Accident (DBA) or a blackout. The four diesel generators are electrically and physically

Enclosure to TXX-23045 Page 4 of 33 independent. Each diesel generator and its associated equipment is located in a separate room with walls designed to protect the diesel generators and associated equipment against an earthquake, tornadoes, missiles, and fire.

2.2 Completion Time Change The proposed change would add an extended 14-day CT for an inoperable DG (TS 3.8.1, Condition B), as permitted by BTP 8-8. The 14-day CT will be applied only if there is a suitable Alternate Power Diesel Generator (APDG) (i.e., an alternate AC power source) available and functional. The APDG for each unit provides supplemental diesel generators capable of powering either one of the 6900V safeguards buses during a Station Blackout (SBO) within one hour from the time that the emergency procedures direct their use as the emergency power source. The APDGs have the capacity to bring the affected unit to Cold Shutdown (i.e., Mode 5) conditions. Criteria and instructions on the use of the APDGs are proceduralized, and the Operating staff is trained in their use.

TS Limiting Condition for Operation (LCO) 3.8.1, AC Sources - Operating will be revised as follows:

Condition B (One DG inoperable), Required Action B.4 (Restore DG to OPERABLE status), Completion Time will change from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR in accordance with the Risk Informed Completion Time Program, to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition B entry 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months concurrent with unavailability of APDG AND 14 days OR In accordance with the Risk Informed Completion Time Program. The AND logical connector will be indented one level. The OR logical connector will not be indented.

This proposed change is justified by NUREG-0800, BTP 8-8 as the allowed CT extension for one DG inoperable is 14 days. Alternatively, a CT can be determined in accordance with the Risk Informed Completion Time Program.

This proposed change satisfies the requirement in NUREG-0800, BTP 8-8 to verify the availability of the APDG prior to entering the extended 14-day CT. After the initial verification, BTP 8-8 requires that availability continue to be checked once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (i.e., once per shift). The initial verification should occur within the last 30 days before entering the extended 14-day CT.

This proposed change satisfies the requirement in NUREG-0800, BTP 8-8 that if the APDG becomes unavailable during the extended 14-day CT, it must be returned to an available status, or a shutdown will be commenced within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This condition is only permitted once within any given extended 14-day CT.

provides TS 3.8.1 Markup pages.

provides TS Bases 3.8.1 Markup pages. The TS Bases markup is provided for information only.

Enclosure to TXX-23045 Page 5 of 33 2.3 Reason for TS 3.8.1 Proposed Change (14 Day DG CT)

The 14-day CT for an inoperable DG is to allow sufficient time to perform planned reliability improvement modifications and preventative or corrective maintenance to ensure emergency DG reliability and availability. Additionally, should conditions occur requiring emergency DG corrective maintenance, the proposed change also provides flexibility to resolve emergency DG deficiencies and avoid potential unplanned shutdowns, along with any potential attendant challenges to safety systems during an unplanned shutdown.

Specifically, the 14-day CT provides time to support planned online DG maintenance.

CPNPP, like most stations, is looking to move more maintenance from outages to online work windows to maximize unit availability. The recent extreme cold temperatures in Texas during February 2021 clearly illustrate the need for nuclear generation during extreme weather. Limiting maintenance during outages minimizes grid vulnerability when large nuclear generators in Texas are in refueling outages.

The requested 14-day CT will provide needed operational and maintenance flexibility.

This license amendment will establish a new CT of 14 days with an available APDG.

CPNPP is permitted to use risk-informed extended completion times in accordance with TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times -

RITSTF Initiative 4b, to extend TS CTs based on risk. With the 14-day CT, DG online maintenance could be accomplished without routinely utilizing the provisions in the Risk-Informed Completion Time (RICT) program. The RICT backstop CT estimate for one DG inoperable is 30 days.

2.4 Bases for TS 3.8.1 Proposed Change (14-Day DG CT)

Given the conclusions reached by the deterministic assessments and risk insights that follow, extending the CT associated with an inoperable emergency DG would also provide:

Enhanced Decision Making The Commission stated in its approval of the policy statement on the use of PRA methods that the use of PRA technology should be increased to the extent supported by the state-of-the-art PRA methods and in a manner that complements the NRCs deterministic approach and supports the NRCs traditional defense-in-depth philosophy. The Use of Probabilistic Risk Assessment Methods in Nuclear Regulatory Activities; Final Policy Statement (Reference 5) states:

The use of PRA technology should be increased in all regulatory matters to the extent supported by state-of-the-art in PRA methods and data and in a manner that complements the NRCs deterministic approach and supports the NRCs traditional defense-in-depth philosophy.

and

Enclosure to TXX-23045 Page 6 of 33 PRA and associated analyses (e.g., sensitivity studies, uncertainty analyses, and importance measures) should be used in regulatory matters, where practical within the bounds of the state-of-the-art, to reduce unnecessary conservatism associated with current regulatory requirements, regulatory guides, license commitments, and staff practices.

Permitting an emergency DG to be removed from service for up to 14 days to perform maintenance or to troubleshoot and repair an inoperable DG is acceptable from a risk-informed approach due to a small increase in Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) consistent with the criteria in Regulatory Guides 1.174 and 1.177. The insights of the risk assessment are provided in Section 3.13.

Efficient Use of Resources The 14 -day CT associated with an inoperable emergency DG will improve the effectiveness of the allowed maintenance period. Plant resources can be more focused on the DG rather than preparation and return to service activities. Under the current 72-hour CT, a significant portion of maintenance activities are usually associated with preparation and return to service tasks; the durations of which are relatively constant. Longer durations allow more focused maintenance to be accomplished during a given maintenance window and therefore would improve maintenance efficiency.

2.5 AC Source Operability Requirements for Shared and Cross-Connectable Systems CPNPP work management processes ensure the unaffected train of shared and cross-connectable systems are protected for the duration of the DG inoperability. A station level procedure directs three control levels to protect plant equipment during maintenance. Level 1 provides administrative information, Level 2 establishes physical barriers, and Level 3 establishes defense in depth (contingency) plans.

These levels of equipment protection are implemented whenever impairment of the unaffected train could result in

a plant trip or transient

loss of the equipments safety function

reduced operating margin

inadvertent entry into TS 3.0.3.

Level 1 Controls include CPNPP work schedules establishing a protected train which ensures the unaffected train is protected. The protected train is relied upon to provide nuclear safety functions and defense in depth for key safety functions. The normal CPNPP work processes establish a protected train for two weeks at a time. This two-week process aligns with a 14-day outage on an emergency DG. This is one example of the administrative actions that are used to protect the unaffected train equipment and

Enclosure to TXX-23045 Page 7 of 33 systems. Other administrative controls include work planning, informational signs, floor marking tape (visual cue), and control of other plant work activities.

Level 2 Controls establish physical barriers through the CPNPP Guarded Equipment Management (GEM) Program. Once the physical barrier is established, the Operations Shift Manager must authorize entry inside the barrier. While at power, CPNPP follows a like-for-like posting process. For example, if Emergency Diesel Generator (DG) 2-02 is inoperable, then Emergency Diesel Generator (DG) 2-01 will be guarded by postings and scheduling. The posting is intended to stop mistakenly making the redundant DG inoperable resulting in a loss of safety function. Once the barriers are established entry must be authorized by the Operations Shift Manager.

Level 3 Controls provide Defense in Depth Contingency Plans (DIDCP). Defense in Depth Contingency Plans go beyond the placement of Guarded Equipment Management (GEM) Signs and barriers and establish additional plans to protect key safety functions and/or provides mitigative actions to be taken in the event a loss of safety function does occur. DIDCPs include integrated planning and scheduling, Level 1 administrative controls, Level 2 barriers to protect key safety functions, and Level 3 defensive measures intended to prevent or mitigate a loss of safety function. The DIDCP should outline activities, procedures, training, or redundant equipment or system availability requirements imposed to reduce the level of risk. For example, with an Emergency Diesel Generator inoperable, the DIDCP will establish Level 2 controls for the switchyard and the preferred and alternate offsite power sources.

Plans are verified to be executable during the CT prior to entry.

3.0 TECHNICAL EVALUATION

3.1 CPNPP AC Power Systems Description The onsite electric system includes power supplies, distribution equipment, and instrumentation and control to supply power to the unit auxiliary loads (normal and safety-related) during startup, normal operation, and normal and emergency shutdown. Connection of the generator outputs to the 345 kV switchyard is via isolated-phase bus (generator main leads), step-up transformers, and transmission lines.

Power to the unit 6900 V auxiliary bus systems is furnished through either the unit auxiliary, station service or startup transformers.

Normally, the non-safety-related auxiliaries are supplied by the main generators through the unit auxiliary transformers. These transformers are connected to the main generator leads, between the generator and main transformers, by means of isolated-phase bus. Safety-related auxiliaries are normally supplied by the preferred offsite power system.

Enclosure to TXX-23045 Page 8 of 33 Two separate and physically independent startup transformers provide startup, preferred and alternate shutdown power to the safety-related auxiliaries of the units on an immediate basis. One transformer is connected to the 345 kV switchyard while the second transformer is connected to the 138 kV switchyard; these transformers are connected to the safety-related 6900 V auxiliary bus systems and, as such, provide two independent means of supplying the safety-related equipment from the offsite power system without relying on the main generator.

Two station service transformers provide power to the non-safety-related auxiliaries.

These transformers are connected to the 345 kV switchyard. One transformer is connected to the non-safety-related 6900 V auxiliary buses of one unit while the second transformer is connected to the non-safety-related 6900 V buses of the other unit.

In addition, the 25 kV Plant Support Power Loop, fed from the 138 kV switchyard, supplies power to non-safety-related equipment. The 25 kV Plant Support Power Loop also supplies alternate power (through manual transfer switches) to certain essential equipment in plant Modes 5 and 6 during safety-related bus outages.

Upon loss of all Offsite AC power, station standby power sources, consisting of four diesel generators (two per unit) are provided to satisfy the loading requirements of the AC safety-related loads. System redundancy precludes loss of all onsite power as a result of any single failure.

Offsite Power System The transmission system serves as the main outlet and source of offsite power for CPNPP. Connection of the station outputs to the system is achieved via 345 kV overhead lines to the 345 kV switchyard. Separate connections to the 138 kV switchyard and the 345 kV switchyard provide independent and reliable offsite power sources to the Class 1E systems of each unit.

Because the 345 kV system forms the backbone of the Transmission Operator (TO) transmission system, it provides a highly reliable source of continuous power for plant shutdown. Another reliable source is the 138 kV network.

The high-voltage (HV) switchyards at CPNPP consist of 345 kV switching facilities and 138 kV switching facilities and are an integral part of the transmission system.

The network interconnections to CPNPP switchyards are made through seven 345 kV and two 138 kV transmission lines to other switching stations within the system (Figure 1). There are no interconnections between the 138 kV switchyard and the 345 kV switchyard at CPNPP. The 138 kV switchyard is physically and electrically independent of the 345 kV switchyard (Figure 1).

Essentially, the 345 kV and the 138 kV switchyards each consist of a two-bus arrangement having one breaker per transmission circuit. Transmission circuits terminate in individual positions on alternate buses in the switchyards. Power can be supplied to each switchyard from any of their respective transmission circuits.

Enclosure to TXX-23045 Page 9 of 33 Two three-phase, half-size, step-up transformers are provided for each unit to raise the 22 kV main generator voltage to 345 kV prior to transmission via overhead lines to the CPNPP 345 kV switchyard. Each CPNPP unit output line is connected to both 345 kV buses through two breakers which function as generator circuit breakers.

The units are synchronized to the system across the generator circuit breakers. In the event of a unit trip, these breakers isolate the associated generator from the system.

The CPNPP offsite power source line for startup transformer XST1 is connected to both 138 kV buses through two breakers which function as a bus tie. The offsite power source line for startup transformer XST2 is connected to both 345 kV buses through two breakers which function as a bus tie.

Startup transformer XST1 and alternate startup transformer XST1A are connected to a common overhead line from the 138 kV switchyard. Each transformer is provided with a 138 kV motor-operated air switch such that each transformer can be energized independent of the other transformer.

Startup transformer XST2, alternate startup transformer XST2A and station service transformer 1ST are connected to a common overhead line from the 345 kV switchyard. Each transformer is provided with a 345 kV motor-operated air switch such that each transformer can be energized independent of the other transformer.

Alternate startup transformer XST1A is located under the 138 kV line to XST1 (Figure 1) to serve as a replacement of XST1 to provide 138 kV offsite power to Units 1 and 2 safety related buses. Cable buses from secondary X and Y windings of XST1 and XTS1A are connected to two 6.9kV transfer panels to provide 138 kV offsite power to Units 1 and 2 safety related buses. These transfer panels allow transfer of 138 kV offsite power source for safety related buses from XST1 to XST1A and vice versa.

Alternate startup transformer, XST2A with dual primary windings (345 kV and 138 kV), is in a location under the 345 kV line to XST2 (Figure 1) to serve as a replacement of XST2. Cable buses from secondary X and Y windings of XST2 and XTS2A are connected to two 6.9kV transfer panels to provide 345 kV offsite power to Units 1 and 2 safety related buses. These transfer panels allow transfer of 345 kV offsite power source for safety related buses from XST2 to XST2A and vice versa.

Station service transformer 2ST is connected to the 345 kV switchyard east and west bus via circuit breakers and an overhead line.

The 138 kV and 345 kV circuit breakers are provided with an energy storage mechanism that allows the operation of the individual circuit breaker without having an external source of power. The circuit breakers have two separate avenues of relay protection termed primary and secondary or backup to provide a high degree of operational reliability.

Physical layouts of the switchyards are shown in (Figure 1).

Enclosure to TXX-23045 Page 10 of 33 The substations that are connected to the CPNPP switchyards (Figure 1) are as follows:

Carmichael Bend (138 kV)

Stephenville (138 kV)

Mitchell Bend (345 kV)

Wolf Hollow (345 kV)

Timberview (345 kV)

Johnson (345 kV)

Comanche (345 kV)

Parker No. 1 (345 kV)

Parker No. 2 (345 kV)

Onsite Power System The onsite AC Power Systems consist of various auxiliary electrical systems designed to provide reliable electrical power to Class 1E and non-Class 1E station loads.

Redundancy of Class 1E onsite AC Power Systems ensures safe reactor shutdown during a Safe Shutdown Earthquake (SSE) or DBA coincident with any single failure within the standby AC Power System or the 118 V uninterruptible AC Power System.

The standby AC Power System ensures safe plant shutdown when the preferred and alternate offsite power sources are not available. The 118 V uninterruptible AC Power supply feeds power to reactor protection instrumentation and control systems and to other Class 1E components and systems essential to safe reactor operation.

Any one of the following systems can supply power to the Class 1E onsite AC power distribution systems:

1. Preferred power system (offsite power sources, 345 kV source for Unit 1 and 138 kV source for Unit 2)

2. Alternate power system (alternate offsite power source, 138 kV source for Unit 1 and 345 kV source for Unit 2)

3. Standby power system (diesel generators)

CPNPP has also provided a non-safety related Alternate Power Diesel Generator (APDG) for each unit with the capability to connect to a Class 1E train to provide defense-in-depth for safe shutdown of a unit during outages or during extended duration of an inoperable offsite circuit on occurrence of concurrent loss of offsite power and failure of DGs. The APDGs may provide 3450 kVA to provide long term cooling of each unit.

Enclosure to TXX-23045 Page 11 of 33 3.2 Grid Reliability The bulk transmission system of the Electric Reliability Council of Texas (ERCOT) and the Transmission Operator transmission system are designed to withstand the loss of the largest power plant and to retain the integrity of the remaining bulk transmission system.

The full load capacity of CPNPP at the time of Unit 1 installation represented two to three percent of the ERCOT estimated peak load and, with the addition of the second unit, was equivalent to approximately five to six percent of the estimated peak.

Actual disturbances on the ERCOT system have occurred where large amounts of capacity were lost, one as high as 10 percent, with no integrity degradation of the transmission system observed.

Studies confirm that loss of the CPNPP plant when 100 percent loaded will not impair the integrity of the bulk transmission system for conditions representative of those projected at the time of installation of Unit 1 or both Units 1 and 2.

The stability studies demonstrate both the effect on the transmission system when one or both of the CPNPP units are lost and when the plant auxiliaries are transferred to the standby source. It is evident from the studies that loss of one or both of the nuclear units will not cause the loss of auxiliary power to the station. In addition, the system remains stable for all disturbances near CPNPP which are cleared by primary or backup relaying.

Simultaneous loss of either unit and the most critical Generator does not affect the capability of either offsite source to supply shutdown power on an uninterrupted basis.

Simultaneous loss of either unit and the most critical transmission line does not adversely affect the capability of the system to furnish shutdown power on an uninterrupted basis.

The normal operating voltages at CPNPP for the 345 kV and 138 kV (nominal) offsite power grid are approximately 354 kV and 142 kV. These normal operating voltages are subject to periodic review and adjustment based on the requirements of the TO system which may change during the operating life of CPNPP.

The maximum voltages at CPNPP are 361 kV and 144 kV. These maximum grid voltages are based on equipment ratings (circuit breakers, transformers, etc.) and are controlled by generator excitation (throughout the grid) and switching of shunt reactors and capacitors. The minimum voltage for the respective grids at CPNPP has been calculated to be 340 kV and 135 kV for normal and credible contingency conditions respective to CPNPP.

On the basis of these voltage ranges of 340 kV to 361 kV and 135 kV to 144 kV for the offsite power sources, class 1E bus voltage ranges are determined to be within the out-of-tolerance voltage values. All class 1E equipment can operate continuously at these voltages for all modes of plant operation to perform their safety function.

Enclosure to TXX-23045 Page 12 of 33 Grid voltages lower than those calculated could occur for situations involving contingencies in the grid system. Periodically, such situations are studied. These studies are conducted in accordance with the ERCOT Planning Criteria and the TO Transmission Planning Procedures.

The nominal frequency on the ERCOT system is 60 +/-.03 Hz. On occasion when large amounts of generation are lost, the frequency will drop to 59.6 Hz and recover within a few seconds to 59.8 Hz and within a few minutes to normal, 60.0 Hz. The deviations in frequency are well within the operating ranges of the Class 1E equipment.

Studies have been and are continually being made where catastrophic disturbances are postulated to test the ERCOT system against events beyond the design criteria.

The lowest frequency observed on these studies has been 57.5 Hz, for which the system recovered with no cascading shutdowns.

The frequency decay rates observed on the ERCOT system during daily operation are usually less than 1.5 Hz/sec. Location or origin of disturbance should have little effect on frequency decay rate. The type of system disturbance postulated in the above studies resulted in a maximum calculated frequency decay rate of 2.4 Hz/sec.

One inconceivable situation has been studied to determine a maximum frequency decay rate at Comanche Peak which resulted in a calculated decay rate of 4.37 Hz/sec. This situation envisioned the total Dallas/Fort Worth metro area load being loaded on Comanche Peak instantaneously and all other sources of generation removed.

In order to satisfy offsite power requirements, the TO adjusts grid parameters to maintain 345 kV grid system voltage at CPNPP switchyard between the voltage range of 340 kV to 361 kV and 138 kV grid system voltage at CPNPP switchyard between the voltage range of 135 kV to 144 kV.

Grid configuration and reliable operation is maintained through tested and proven operating procedures and guidelines. TO is a member of ERCOT which continually plans (coordinates) the capacity online (to serve load), the amount of responsive reserve, the maintenance of units, the maintenance of grid components, and the scheduled transfer of energy between members. Many entities in ERCOT have their own control centers where the systems are monitored. Parameters monitored in these control centers are system frequency, grid voltages (at many points on system), generation (all units), transmission line flows, and reserve capacity. Through use of these tools and adherence to operating guides, experience has proven grid integrity over a long period of time.

The responsive reserve on the ERCOT system is coordinated by the ERCOT.

ERCOT maintains a minimum responsive reserve of 2300 MW. The amount of responsive reserve is subject to periodic review and adjustment based on the requirements of ERCOT, which may change during the operating life of CPNPP. This reserve is shared among all operating plants and loads acting as resources (interruptible loads) throughout the system and not concentrated in specific areas or

Enclosure to TXX-23045 Page 13 of 33 any particular plant. No restrictions are placed on specific responsive reserve in relation to Comanche Peak.

The 14-day extended Completion Time does not affect grid reliability. Grid reliability evaluation shows that a 14-day Completion Time is supported.

3.3 Station Blackout Capability Both units are capable of coping with a station blackout (SBO) for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months as AC-Independent plants. The 4-hour coping duration was determined by approved methods based on the redundancy and reliability of onsite emergency AC power sources, the expected frequency of loss of offsite power, and the probable time needed to restore offsite power.

The reactor coolant system with associated support systems were analyzed and determined to be capable of maintaining the appropriate core cooling and containment integrity during a 4-hour postulated SBO event.

Because CPNPP Units 1 and 2 have certain common cooling systems, the evaluation showed that no equipment modifications were required for a blacked out unit to cope with a Station Blackout event. In the event that a single DG is not available in the Non-SBO Unit, such as during two train DG outages, no credit is taken for these common cooling systems for the SBO Unit.

SBO coping is not directly covered by Technical Specification (TS) requirements; however, SBO coping equipment are covered by various Technical Specification requirements which are consistent with the coping analysis assumptions when the units are in MODES 1 through 6. In the event that a single DG is not available in the Non-SBO Unit, such as during two train DG outages, credit is not taken for a Non-SBO Units DG. This is because it has been demonstrated that the SBO unit can cope without the common systems powered by the Non-SBO Units DG. Unit outages that remove two trains of SSW or two trains of CCW or two trains of Safety Chilled Water would put the UPS cooling units in the same configuration as a two train DG outage. In addition, Unit outages that remove two trains of SSW or two trains of CCW would put the Control Room air conditioning units in the same configuration as a two train DG outage.

The 14-day extended Completion Time for one DG inoperable does not affect the Station Blackout Capability.

3.4 Alternate Power Diesel Generators (APDG)

For Each Unit, a Non-Class 1E diesel generator package has been provided and is intended to supply power to one 6.9 kV safeguards bus during a beyond design basis event due to loss of offsite power coincident with failure of both Class 1E emergency diesel generators. These diesel generator packages are capable of providing power (3450 kVA) to either safeguards 6.9 kV bus on their respective unit. The APDG output of 3,000 kVA is sufficient to take their respective unit to MODE 5 (Cold Shutdown).

Enclosure to TXX-23045 Page 14 of 33 The APDGs are operated and loaded in accordance with station procedures. These procedures ensure that the APDGs are not overloaded during startup or operation.

Because of the methodical operation provided by the station procedures, the APDGs are an acceptable alternate power source as required by BTP 8-8. The APDGs can provide a power source which provides the power necessary to take the affected unit to MODE 5.

In accordance with BTP 8-8, this proposed change supports the NRCs desire to base its decisions on the results of traditional engineering evaluations, supported by insights (derived from the use of PRA methods) about the risk significance of the proposed changes. This is a clear example of when risk insights coupled with deterministic analysis of the desired operation indicates the extended 14-day Completion Time for DG online maintenance is acceptable. The Risk Informed Completion Time (RICT) Program supports a 30-day Completion Time and this proposed change is for less than half that time under normal plant maintenance and scheduling controls.

3.5 Fire Hazards For fires that affect both preferred and alternate power source bus ducts, the CPNPP fire protection program has provided adequate protection to ensure safe shutdown can be achieved. For other single external events, the bus duct and cable tray construction, separation and independence provided between the preferred and alternate power source bus ducts assure that simultaneous failure of both bus ducts/cable trays will not occur. For example, separate independent circuits are provided for the bus duct connections to the onsite distribution systems. The possibility of a single external fire near the west wall of the Auxiliary Building causing damage to bus ducts A2, B1 and B2, is minimized by the inaccessible location of the subject ducts and the following features:

1. There are no fixed external ignition sources located in this area;

2. Inaccessibility to the area restricts the introduction of transient combustible materials;

3. Thermal type fire detectors and a fixed wet pipe sprinkler system are provided in this area;

4. Bus duct enclosures consist of totally enclosed ventilated metal type construction;

5. Bus duct cables meet the flame test requirements of IEEE 383-1974; and,

6. Bus ducts and cable trays are separated from the rooms below by a concrete fire barrier roof.

3.6 Training Licensed Operators and Non-Licensed Operators are trained on the purpose and use of the APDGs. Using a combination of the plant simulator and plant Job Performance Measures, the operators periodically display their ability and proficiency to respond to a loss of all AC power (i.e., Station Blackout), which includes walking through the actions required to ensure the APDGs are available to provide power to the station

Enclosure to TXX-23045 Page 15 of 33 within one hour from the time that the emergency procedures direct their use as the emergency power source.

3.7 Maintenance Rule Program (10 CFR 50.65)

Using the full duration of the requested 14-day CT will be infrequent. CPNPP programs, such as the Maintenance Rule Program, will ensure the extended emergency DG CT is not used frequently. Frequent use of the full CT would adversely impact emergency DG unavailability, which could result in not meeting Maintenance Rule performance goals, and would thus require corrective actions and increased management focus to restore the emergency DGs to Maintenance Rule 10 CFR 50.65(a)(2) status.

The reliability and availability of the emergency DGs are monitored under the Maintenance Rule Program. The Maintenance Rule Program performance criterion for unavailability provides a control mechanism on the usage of the extended emergency DG CT. The Maintenance Rule Program requires an evaluation to be performed when equipment covered by the Maintenance Rule does not meet its performance criteria. If the pre-established reliability or availability performance criteria are not achieved for the emergency DGs, they are considered for 10 CFR 50.65(a)(1) actions. Those actions would require increased management attention and goal setting to restore their performance to an acceptable level. The actual out-of-service time for the emergency DGs is minimized to ensure the Maintenance Rule availability performance criterion is met.

The APDGs will be included in the scope of the CPNPP Maintenance Rule Program and will be classified and implemented in accordance with plant procedures.

3.8 Work Management The CPNPP Work Management program ensures the extended emergency DG CT is monitored appropriately. The CPNPP online risk management process is designed to minimize plant risk through a blended approach of quantitative and qualitative risk assessment. The blended approach uses the best information available based on both PRA studies and traditional deterministic approaches to assess and manage risk.

A station procedure and a configuration risk monitor (also available to the Control Room) provide the tools to perform a Maintenance Risk Assessment. A Maintenance Risk Assessment is an evaluation of the scenario, probability and consequences of maintenance actions to manage the cumulative effect on CDF and LERF when multiple SSCs are made inoperable or unavailable.

During MODEs 1 and 2, the Work Control On-Line Scheduling Supervisor or Manager shall ensure the cumulative effect on plant safety is evaluated by performing a Maintenance Risk Assessment whenever multiple systems, including support systems, are made or become unavailable. The Maintenance Risk Assessment shall include Level I Internal Events and Level II Issues and External Events.

Enclosure to TXX-23045 Page 16 of 33 The Core Damage Frequency provides an appropriate measure of Level I performance. The Large Early Release Frequency provides an appropriate measure of Level II performance.

Switchyard activities should not be scheduled or performed concurrently with activities on electrical systems, Turbine Driven Auxiliary Feedwater, Emergency Diesel Generator, Station Service Water, or the Blackout Sequencer.

Crane use and man-lifts around energized transformers or power lines are prohibited with activities on electrical systems, Turbine Drive Auxiliary Feedwater, Emergency Diesel Generator, Station Service Water, the Blackout Sequencer, or during reduced inventory operations.

One complete ECCS train that can be actuated automatically shall be maintained available.

The CPNPP Work Management Philosophy is an integral element in successful risk management (Attachment 4).

3.9 Engineering Considerations For an SBO during the proposed extended CT, the APDGs would be available to mitigate the accident, and the units would remain within the bounds of the accident analyses. In addition, there would be no adverse impact to the units, because the Safety Function Determination Program (SFDP) will be utilized to ensure that cross-train checks are performed to ensure a loss of safety function does not go undetected. The SFDP will also ensure appropriate actions are taken if a loss of safety function is identified. Since the probability of a loss of safety function going undetected during a planned maintenance window is low, there is minimal safety impact due to the proposed extended CT for an inoperable DG.

The combination of defense-in-depth and safety margin principles inherent in the onsite emergency power system ensures an emergency supply of power will be available to perform the required safety function. These elements of defense-in-depth and safety margin support a CT extension to 14 days to allow a DG to be out of service for a longer period of time.

3.10 Defense-In-Depth The proposed change to the CT for a DG out of service maintains system redundancy, independence and diversity commensurate with the expected challenges to system operation. The other DGs, offsite power and the associated engineered safety equipment will remain OPERABLE to mitigate the consequences of any previously analyzed accident. Otherwise, the SFDP will require that a loss of safety function be declared, and the appropriate TS Conditions and Required Actions are taken. In addition to the SFDP, the Work Management process provides for controls and assessments to preclude the possibility of simultaneous outages of redundant trains and to ensure system reliability. The Maintenance Rule performance measure for unavailability also provides a control mechanism on the usage of the

Enclosure to TXX-23045 Page 17 of 33 extended CT. The proposed increase in the CT associated with an inoperable DG while a CPNPP unit is in MODEs 1, 2, 3 or 4, will not alter the assumptions relative to the causes or mitigation of an accident.

With a DG inoperable at CPNPP, a loss of function has not occurred. The remaining offsite power sources and DG are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure.

As defined by Regulatory Guide 1.174, consistency with the defense-in-depth philosophy is maintained if the following occurs regarding the proposed licensing basis change:

A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation.

The installed additional AC power supply (i.e., APDGs) will ensure a reasonable balance is preserved between prevention of core damage, prevention of containment failure and consequence mitigation for the proposed extension to the current CPNPP TS 3.8.1 CT for one inoperable DG to 14 days. The proposed CT extension will not significantly reduce the effectiveness of any of the following four layers of defense that exist in the plant design:

minimizing challenges to the plant, preventing any events from progressing to core damage, containing the radioactive source term, and emergency preparedness.

Extending the CT for one inoperable DG does not increase the likelihood of initiating events and does not create new initiating events. Furthermore, the proposed CT extension does not significantly impact the availability and reliability of SSCs that are relied upon to perform safety functions that prevent plant challenges from progressing to core damage. Lastly, the proposed change does not significantly impact the containment function or SSCs that support the containment function and also does not involve the emergency preparedness program or any of its functions.

Over-reliance on programmatic activities as compensatory measures associated with the change in the licensing basis is avoided.

As prescribed in BTP 8-8, a supplemental power source (i.e., APDGs) is installed and will be available as a backup to an inoperable DG to maintain the defense-in-depth design philosophy for the electrical power system to meet its intended safety function.

The installation of the APDGs (i.e., plant equipment) reduces the reliance on programmatic activities as compensatory measures associated with the proposed TS CT change.

Plant safety systems are designed with redundancy so that when one train is inoperable, a redundant train can provide the necessary safety function. The

Enclosure to TXX-23045 Page 18 of 33 preferred approach at CPNPP for accomplishing safety functions is through engineered systems, rather than overreliance on programmatic activities (i.e.,

compensatory measures). During the timeframe when a DG is inoperable, an existing redundant source of power will be maintained OPERABLE. As previously highlighted, in the event the other equipment becomes inoperable concurrent with the DG inoperability, the SFDP requires cross-train checks to ensure a loss of safety function does not go undetected. If a loss of safety function is identified, TS LCO 3.0.6 will require entry into the applicable Conditions and Required Actions for the system that possesses the loss of safety function.

System redundancy, independence, and diversity are preserved commensurate with the expected frequency, consequences of challenges to the system, and uncertainties (e.g., no risk outliers).

The redundancy, independence and diversity of the onsite emergency power system at CPNPP will be maintained during the extended CT. There were no identified uncertainties in redundancy, independence and diversity with the introduction of the APDGs or the extended CT. The APDGs are not susceptible to the same common cause failures as the installed emergency DGs since the APDGs have a different manufacturer, operate at different speeds, have different starting systems, etc. Thus, the proposed change improves the independence and diversity of the onsite AC power sources.

Defenses against potential common-cause failures are preserved, and the potential for the introduction of new common-cause failure mechanisms is assessed.

Defenses against common cause failures are preserved. New common cause failure mechanisms are not created as a result of the proposed change to extend the CT for one DG inoperable. The additional AC power supply (i.e., APDGs) does not have any common linkage with the existing emergency DGs. The operating environment and operating parameters for the emergency DGs remains constant; therefore, new common cause failure modes are not introduced. Redundant and backup systems are not impacted by the proposed change and no new common cause links between the primary and backup systems are introduced.

Independence of barriers is not degraded.

The barriers protecting the public and the independence of these barriers are maintained. Multiple DGs, systems and electrical distribution systems will not be taken out-of-service simultaneously, as that could lead to degradation of the barriers and an increase in risk to the public. In the event other equipment becomes inoperable concurrent with DG inoperability, the SFDP requires cross-train checks to ensure a loss of safety function does not go undetected. If a loss of safety function is identified, TS LCO 3.0.6 will require entry into the applicable Conditions and Required Actions for the system that has the loss of safety function.

TS 3.8.1, RA B.2 requires declaring required feature(s) supported by the inoperable DG, inoperable when its redundant required feature(s) are inoperable. RA B.2 is

Enclosure to TXX-23045 Page 19 of 33 intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These required features within the context of RA B.2 are designed to be powered from redundant safety related 6.9 kV emergency buses. Redundant required feature failures consist of inoperable features associated with an emergency bus redundant to the emergency bus that has an inoperable DG.

In addition, the extended CT does not provide a mechanism that degrades the independence of the fission product barriers; fuel cladding, reactor coolant system and containment.

Defenses against human errors are preserved.

The proposed extension to the CT does not introduce any new operator actions for the existing plant equipment. However, operators will be required to align and operate the APDGs. Operating the APDGs is a task in the current non-licensed operator training program and has been for many years. Aligning and operating the APDGs are tasks in the initial and recurrent non-licensed operator training programs.

These tasks are directed by validated and approved procedures.

Training for the licensed operators and non-licensed operators on the APDGs includes simulator, classroom, and on-the-job training. The APDGs can be started and loaded within one hour from the time they are selected as the desired power source in procedure ECA-0.0A/B, Loss of All AC Power. The procedures and plant labeling program guard against human performance errors.

The intent of the plants design criteria is maintained.

The design and operation of the emergency DGs are not altered by the proposed CT change. The safety analyses safety criteria stated in the CPNPP FSAR is not impacted by the proposed change. Redundancy and diversity of emergency DGs is not altered because system design and operation are not changed by the proposed CT change. The proposed change to TSs will not allow plant operation in a configuration outside each plants design basis. The requirements credited in the accident analyses regarding the emergency DGs remain the same.

3.11 Safety Margin When the CPNPP units are in MODEs 1, 2, 3 or 4 and operating in the extended CT for an inoperable DG, the plants remain in a condition for which they have been analyzed; therefore, from a deterministic perspective, the proposed TS change is acceptable. The 14-day CT utilizes risk-insights based on plant specific analyses using the methodology defined in this license amendment request. The Maintenance Rule (i.e., 10 CFR 50.65) requires each licensee to monitor the performance or condition of DGs to ensure they are capable of performing their intended safety function. If the performance or condition of the DGs do not meet performance criteria, appropriate corrective action is required along with goals to monitor the effectiveness of corrective actions. Additionally, the Maintenance Rule performance

Enclosure to TXX-23045 Page 20 of 33 measure for unavailability also provides a control mechanism for the usage of the extended CT.

The installed APDGs support the proposed TS change, as they supply supplemental AC power sources, for each unit with the capability to power either safeguards bus within one hour from the time that emergency procedures direct their use as the emergency power source. The APDGs have the capacity to bring the affected unit to cold shutdown (MODE 5).

The evaluation that follows, using the principles defined in RG 1.174, demonstrates that the proposed licensing bases changes, are consistent with the principle that sufficient safety margins are maintained.

With sufficient safety margins, the following are true for CPNPP:

Codes and standards or their alternatives approved for use by the NRC are met.

The design and operation of the emergency DGs is not altered by the proposed CT extension or use of the APDGs. Redundancy and diversity of the electrical distribution system will be maintained. The APDGs provide an additional AC power source as a defense-in-depth measure for SBO.

Safety analysis acceptance criteria in the LB (e.g., FSAR, supporting analyses) are met or proposed revisions provide sufficient margin to account for analysis and data uncertainty.

The safety analyses acceptance criteria stated in the CPNPP FSAR is not impacted by the proposed change. The proposed change does not allow plant operation in a configuration outside the design bases. The requirements regarding the emergency DGs credited in the accident analyses remain the same.

Vistra OpCo concludes that safety margins are not negatively impacted by the proposed change.

3.12 Deterministic Assessment of Proposed DG Completion Time Change The safety-related systems are designed with sufficient capacity, independence, and redundancy to ensure performance of their safety functions assuming a single failure.

The offsite electrical power system also provides independence and redundancy to ensure an available source of power to safety-related loads. Upon loss of the preferred power source to any 6.9 kV Class 1E bus, the alternate power source is automatically connected to the bus and the diesel generator starts should the alternate source not return power to the Class 1E buses. Loss of both offsite power sources to any 6.9 kV Class 1E bus, although highly unlikely, results in the emergency diesel generator providing power to the Class 1E bus.

Two independent diesel generators and their distribution systems are provided for each unit to supply power for the redundant onsite AC Power System. Each diesel generator and its distribution system are designed and installed to provide a reliable

Enclosure to TXX-23045 Page 21 of 33 source of redundant onsite generated (standby) AC power and are capable of supplying the Class 1E loads connected to the Class 1E bus which it serves.

The impact of the proposed change would allow continued power operation at CPNPP up to an additional 11 days while DG maintenance, modification, or testing is performed. The DG is a standby electrical power supply whose safety function is required when both the preferred and alternate offsite power supplies are unavailable, and an event occurs that requires operation of the plant engineered safety features.

Independent standby power systems are provided at CPNPP with adequate capacity and testability to supply the required engineered safety features and protection systems. The standby power sources are designed with adequate independence, redundancy, capacity and testability to ensure power is available for the engineered safety features and protection systems required to avoid undue risk to the health and safety of the public. These standby power sources will successfully provide the required capacity when a failure of a single active component is assumed.

Each of the four emergency DGs can supply one of the four separate Class 1E emergency buses. Each DG is started automatically on a Loss of Offsite Power (LOOP) or Safety Injection. The DG arrangement provides adequate capacity to supply the engineered safety features for the design basis accident (DBA), assuming the failure of a single active component in the system.

Since the standby power systems can accommodate a single failure, extending the CT for an inoperable DG has no impact on the system design basis. Safety analyses acceptance criteria, as provided in the CPNPP FSAR, is not impacted by the proposed change. AC power sources credited in the accident analyses will remain the same.

To ensure that the single failure design criterion is met, LCOs are specified in CPNPP TSs requiring all redundant components of the onsite power system to be OPERABLE. In the event that a DG is inoperable in MODEs 1, 2, 3 and 4, existing CPNPP TS 3.8.1 RA B.1 requires verification of the OPERABILITY of the offsite circuits on a more frequent basis (every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months ). When the required onsite power system redundancy is not maintained, action is required within the specified CT to initiate a plant shutdown. The CT provides a limited time to restore equipment to OPERABLE status and represents a balance between the risk associated with continued operation without the required system or component redundancy and the risk associated with initiating a plant transient while transitioning the unit to a shutdown condition. Thus, the acceptability of the maximum length of the extended CT interval relative to the potential occurrences of design basis events is considered.

Since a proposed extension to the CT for a single inoperable DG does not change the design basis for the standby onsite emergency power system (i.e., DGs), the proposed change is acceptable and consistent with the intent of BTP 8-8.

In accordance with Generic Letter 80-30, Clarification of the Term Operable as It Applies to Single Failure Criterion for Safety Systems Required by TS,(Reference 9)

CPNPP proposes the extended CT will follow;

Enclosure to TXX-23045 Page 22 of 33 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.

Implementation of the extended CT will continue to provide a limited time to fix equipment or otherwise make it OPERABLE while avoiding a plant shutdown. The extended CT will continue to assure that no set of equipment (i.e., DG) outages would be allowed to persist that would result in the facility being in an unprotected condition.

CPNPP coping time during an SBO is not affected by the proposed change to extend the CT for one inoperable DG. The coping time is calculated based on guidance provided in NUMARC 87-00, Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors (Reference 6). The assumptions and the results of the SBO analyses are not changed by an extension of the CT, and compliance with 10 CFR 50.63 is maintained. In addition, DG reliability will be maintained at or above the SBO target level of 0.95, and the effectiveness of maintenance on the DGs and support systems will be monitored pursuant to the Maintenance Rule. The Maintenance Rule performance measure for unavailability also provides a control mechanism for the usage of the extended CT.

Vistra OpCo concludes that extending the CPNPP CT for a single inoperable DG from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days is acceptable because plant design basis is not impacted.

The 11-day extension of the CT is consistent with BTP 8-8. The impact of extended plant operation is evaluated in a probabilistic framework in the discussion that follows.

3.13 Risk Insights To ensure that the risk associated with extending the CT for a DG is minimized and consistent with the philosophy of maintaining defense-in-depth, preparatory measures will be taken. The required availability of APDGs in order to enter the extended CT for one inoperable DG is incorporated into the proposed change. These measures are provided in Attachment 5, 14-Day Completion Time Entry and are listed in the Technical Specification Bases for Required Action B.4. These measures will ensure the risk associated with removing a DG from service is appropriately managed during the extended CT for one inoperable DG.

Without approval of an extended CT, voltage regulator, governor and diesel starting air work could require an extended refueling outage so that a DG could be removed from service without any TS implications. Additionally, if an unplanned DG outage occurs while at power, and the DG is not restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , a unit shutdown would be required upon expiration of the 72-hour CT provided in TS 3.8.1. Shutdown of either plant involves many plant operator activities and plant

Enclosure to TXX-23045 Page 23 of 33 evolutions that challenge plant equipment, present opportunities for operator error and increase the possibility of an unplanned plant trip. It should also be noted that shutdown of a unit does not remove the desire to have a DG available to support its associated Class 1E bus. A unit that is shutdown still requires operation of the Residual Heat Removal system, which is dependent on an OPERABLE Class 1E bus. By granting the proposed license amendment and allowing continued steady state operation, additional operator activities and plant evolutions associated with a plant shutdown are avoided. The increased possibility of a plant trip is also minimized. The proposed change for an additional 11 days to the CT for one inoperable DG is a reasonable amount of time for which a regulatory basis exists.

The additional time by which the CT would be extended is considered small. Due to the short time period the probability of a design basis accident occurring during this interval is considered to be low.

3.14 Risk Assessment Although the proposed change is based on deterministic criteria, the proposed change to the allowable CT for the Required Actions associated with restoration of an inoperable Emergency Diesel Generator has been evaluated using risk assessment techniques and insights. The assessment of the EDG CT extension considered various factors to address the impact of the extension on the CPNPP PRA model.

The analysis included a review of internal events, external events, identified risk reduction measures, and the Configuration Risk Management Program.

The CPNPP PRA models are sufficiently robust and suitable for use in risk informed processes such as for regulatory decision making, including the Risk-Informed Extended Completion Time application (TSTF-425, R2), as evidenced by the NRCs Safety Evaluation (Reference 10). The peer reviews that have been conducted and the resolution of findings from those reviews demonstrate that the internal events, internal flooding, and fire models of the PRA have been performed in a technically correct manner. The assumptions and approximations used in development of the PRA have also been reviewed and are appropriate for this application.

Individual assessments of the CT extension were performed for Internal Events, Internal Flooding and Internal Fires based on the plants PRA models. High winds, Seismic events, and other external events use insights from the IPEEE analysis.

These evaluations concluded risk impacts are small and support the overall conclusions of this assessment.

The above approach demonstrates that the following principles for the proposed change:

The applicable regulatory requirements will continue to be met

Adequate defense-in-depth will be maintained

Sufficient safety margins will be maintained, and

Any increases in CDF and LERF are small and consistent with the NRC Safety Goal Policy Statement and Regulatory Guides 1.174 and 1.177

Enclosure to TXX-23045 Page 24 of 33 Constraints on concurrent maintenance of other equipment while an Emergency Diesel Generator is unavailable are defined to ensure that the risk increase due to the proposed change is small. Based upon these evaluations, including quantitative and qualitative considerations, the risk results and insights support the deterministic request to extend the Emergency Diesel Generator CT to 14 days.

Quantitative and qualitative contributions to total Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) fall below the threshold levels that allow consideration using evaluation of risk impact from proposed changes (i.e., CDF less than 1E-4 per year and LERF less than 1E-5 per year). The risk impact associated with the proposed extension is evaluated in the risk assessment which is summarized in the following sections and constitutes an acceptable change in risk where effective risk management actions are implemented to reduce risk. The risk assessment is broad and includes all hazard groups and plant operational states applicable to the CT extensions.

The following risk importance measures are used to evaluate the proposed CT extension to the Technical Specifications:

Changes in Core Damage Frequency (CDF)

Changes in Large Early Release Frequency (LERF)

Incremental Conditional Core Damage Probability (ICCDP)

Incremental Conditional Large Early Release Probability (ICLERP)

Threshold values of ICCDP and ICLERP from RG 1.177 (Reference 4), ICCDP < 1E-05 and ICLERP < 1E-06, can be considered in this evaluation of an acceptable level of change in risk for the proposed CT extension. This threshold is appropriate given that effective compensatory measures are in place to reduce the overall risk increases. Further, this PRA evaluation is extended to apply thresholds for CDF and ICCDP < 1.0E-06 and LERF and ICLERP < 1.0E-07 as described in RG 1.177 and RG 1.174.

Additional information on the risk assessment and the adequacy of the PRA models used to develop that risk assessment are included in Attachment 6.

3.15 Conclusion Regarding DG Completion Time Change The results of the deterministic evaluation and risk insight assessment described above provide assurance that the equipment required to safely shutdown the plant and mitigate the effects of a design basis accident will remain capable of performing their safety functions when a DG is out of service in accordance with the proposed CTs.

The proposed CTs are consistent with NRC policy and will continue to provide protection for the health and safety of the public. The proposed change advances the objectives of the NRCs PRA policy statement, including safety decision-making enhanced by the use of PRA insights, more efficient use of resources and a reduction in unnecessary burden. In addition, the proposed change meets the following principles:

Enclosure to TXX-23045 Page 25 of 33

1. The proposed change meets the current regulations.

2. The proposed change is consistent with the defense-in-depth philosophy.

3. The proposed change maintains sufficient safety margins.

4. The proposed change results in acceptable risk metrics provided above that are consistent with the criteria in RG 1.174, RG 1.177 and the NRCs PRA policy statement.

Vistra OpCo concludes that the proposed change to the CPNPP licensing bases is acceptable and operation in the proposed manner will not present undue risk to public health and safety or be inimical to the common defense and security.

3.16 Evaluation of AC Source Operability Requirements for Shared Systems The SFDP ensures at least one train of shared components has an OPERABLE emergency power supply any time a DG is inoperable. The systems at CPNPP, which may be supplied from either unit, are Component Cooling Water System (CCWS) through piping cross-connects, Station Service Water System (SSWS) through piping cross-connects, Control Room Emergency Filtration/Pressurization System (CREFS) through electrical diversity, Control Room Air Conditioning System (CRACS) through electrical diversity, Primary Plant Ventilation System (PPVS) - ESF Filtration Trains through electrical diversity, and Uninterruptable Power Supply (UPS)

HVAC System (UPS HVAC) through electrical diversity. Station administrative procedures are used to track component status and the impact on TS SSCs and TS support SSCs. The allowance in TS Section 3.0.6, When a supported system LCO is not met solely due to a support system LCO not being met, the Conditions and Required Actions associated with this supported system are not required to be entered. If a support system becomes inoperable or nonfunctional an SFDP evaluation is required to ensure there is no loss of safety function. If the SFDP identifies a loss of safety function exists, then that LCO is entered and its Required Actions are implemented. The following TS LCOs are affected:

3.7.7 Component Cooling Water (CCW) System 3.7.8 Station Service Water System (SSWS) 3.7.10 Control Room Emergency Filtration/Pressurization System (CREFS) 3.7.11 Control Room Air Conditioning System (CRACS) 3.7.12 Primary Plant Ventilation System (PPVS) - ESF Filtration Trains 3.7.20 UPS HVAC System The Component Cooling Water System is designed so that selected components in either Safeguards Loop may be cross connected to the other unit during emergencies (Figures 2 and 3).

The Station Service Water System is capable of cross connecting trains within the same unit. The system is also capable of cross connecting trains with either train on the other unit (Figure 4).

Enclosure to TXX-23045 Page 26 of 33 The Control Room Emergency Filtration/Pressurization System (CREFS) and the Control Room Air Conditioning System (CRACS) are normally aligned with two CREFS units powered by each unit (four total CREFS units) and two CRAC units powered by each unit (four total CRAC units). (Figure 5).

The primary function of the Primary Plant Ventilation System (PPVS) is to provide a suitable environment for personnel and equipment during normal plant operation by controlling ambient temperatures, humidity and airborne activity levels. This system also maintains a slightly negative pressure.

Eight PPVS Supply Units (Figure 6) are provided and are connected in parallel by two plenums. The PPVS Supply Unit are connected to common intake and supply plenums. The intake plenum gets air from four fresh air intakes and is distributed by the PPVS Supply Units through the supply plenum to various buildings.

Sixteen PPVS Exhaust Filter Units (Figure 7) are provided. Twelve of these units are comprised of a prefilter, 2 HEPA filters (upstream and downstream of the charcoal adsorber), charcoal adsorber, centrifugal fan, inlet and outlet isolation dampers, overall pressure indicating switch, associated instrumentation and deluge water spray system for the charcoal adsorber. Each fan is operated from the control room ventilation panel. These units are classified as non-ESF units.

The remaining four PPVS Exhaust Filter Units are classified as ESF Exhaust filter units. These are comprised of the above components with the exception of the prefilters. Moisture separators and heaters are added to reduce the humidity of the incoming air and ensure the efficiency of the charcoal adsorbers and HEPA filters.

During a Design Bases Accident (DBA) all eight PPVS Supply Units and the twelve Non-ESF PPVS Exhaust Filter Units are de-energized. The four ESF PPVS Exhaust Filter Units are energized to maintain a negative pressure in the plant Radiologically Controlled Area (RCA), which includes the Auxiliary Building, the Fuel Building and both Unit Safeguards Buildings and limit the radioactive release to the atmosphere.

The Uninterruptable Power Supply (UPS) HVAC System is required to maintain an indoor temperature no greater than 104ºF in both the UPS distribution rooms (118VAC 1E Inverters and battery chargers) and AC Equipment Room during normal, upset (abnormal), or emergency modes of plant operation. The system provides 100% redundancy of safety related components to sustain a single active failure without loss of function and preclude common mode failures. The system is common to both units. Electrical power is normally aligned such that each unit is powered from a different unit 1E power.

Normal room cooling is provided to each UPS and Distribution Room by a Room Fan Coil Unit supplied from the Safety Chilled Water System (CHS). The UPS and Distribution A\C System can also provide room cooling during normal plant operations, or Black Out and Safety Injection conditions (Figure 8).

Enclosure to TXX-23045 Page 27 of 33 3.17 Risk Informed Completion Time Front Stop CPNPP is approved to implement the RICT program. For TS 3.8.1 Condition B, Required Action B.4, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months will be considered the front stop for cumulative risk tracking planning purposes. If the RICT program was utilized after entering Required Action B.4 for greater than the 14-day allowed outage time and the APDG was available for the entire duration of the first 14 days of the Required Action B.4 entry, then 14 days may be considered the front stop for cumulative risk tracking purposes.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements 10 CFR 50.63 10 CFR 50.63(a), Loss of all alternating current power requires that each light-water cooled nuclear power plant licensed to operate be able to withstand for a specified duration and recover from a station blackout. The proposed change does not affect CPNPP compliance with the intent of 10 CFR 50.63(a).

10 CFR 50.65 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants requires that preventive maintenance activities must not reduce the overall availability of the systems, structures and components. It also requires that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The proposed change does not affect CPNPP compliance with the intent of 10 CFR 50.65.

10 CFR 50, Appendix A, General Design Criterion 5 GDC 5, Sharing of structures, systems, and components requires that SSCs important to safety not be shared among units unless it can be shown that the sharing will not significantly impair their ability to perform their safety functions, including, in the event of an accident on one unit, an orderly shutdown and cooldown of the remaining unit. The proposed change in this submittal does not affect CPNPP compliance with the intent of GDC 5.

10 CFR 50, Appendix A, General Design Criterion 17 GDC 17, Electric power systems of Appendix A, General Design Criteria for Nuclear Power Plants, to 10 CFR 50 states, in part, that nuclear power plants have onsite and offsite electric power systems to permit the functioning of SSCs that are important to safety. The onsite system is required to have sufficient independence, redundancy and testability to perform its safety function, assuming a single failure.

The offsite power system is required to be supplied by two physically independent circuits that are designed and located so as to minimize, to the extent practical, the likelihood of their simultaneous failure under operating and postulated accident and

Enclosure to TXX-23045 Page 28 of 33 environmental conditions. The proposed change does not affect CPNPP compliance with the intent of GDC 17.

10 CFR 50, Appendix A, General Design Criterion 18 GDC 18, Inspection and testing of electric power systems states that electric power systems that are important to safety must be designed to permit appropriate periodic inspection and testing of important areas and features, such as insulation and connections to assess the continuity of the systems and the condition of their components. The proposed change does not affect CPNPP compliance with the intent of GDC 18.

Regulatory Guide 1.155 RG 1.155, Station Blackout (Reference 7) describes a method acceptable to the NRC staff for complying with the Commission regulation that requires nuclear power plants to be capable of coping with a SBO event for a specified duration. CPNPP adheres to the guidelines of NUMARC 87-00, which is endorsed by RG 1.155. The proposed change does not affect CPNPP conformance to RG 1.155.

Regulatory Guide 1.174 RG 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis describes a risk informed approach, acceptable to the NRC, for assessing the nature and impact of proposed licensing basis changes by considering engineering issues and applying risk insights.

This RG also provides risk acceptance guidelines for evaluating the results of such assessments. RG 1.174 was used for the evaluation of risk for the proposed change.

Regulatory Guide 1.177 RG 1.177, An Approach for Plant-Specific, Risk-Informed Decision Making: Technical Specifications identifies an acceptable risk-informed approach including additional guidance specifically geared towards the assessment of proposed TS CT changes.

Specifically, RG 1.177 identifies a three-tiered approach for the evaluation of the risk association with a proposed CT TS change. RG 1.177 was used for the evaluation of risk provided with this proposed change.

4.2 Precedent The NRC has previously approved changes similar to the proposed changes in this License Amendment Request for other nuclear power plants including:

1. Brunswick Steam Electric Plant: Application dated June 19, 2012 (ADAMS Accession No. ML12173A112); NRC Safety Evaluation dated February 24, 2014 (ADAMS Accession No. ML13329A362).

Similar to Brunswick, Vistra OpCo chose to request a TS 3.8.1 CT extension to 14 days for an inoperable DG. Unlike Brunswick, Comanche Peak has a

Enclosure to TXX-23045 Page 29 of 33 supplemental power source that is capable of taking the affected unit to cold shutdown, meeting the provisions of BTP 8-8.

2. Browns Ferry Nuclear Plant: Application dated November 12, 2010 (ADAMS Accession No. ML103210334); NRC Safety Evaluation dated October 5, 2011 (ADAMS Accession No. ML11227A258).

Similar to Browns Ferry, Vistra OpCo chose to request a TS 3.8.1 CT extension to 14 days for an inoperable DG. The NRC also mentioned in its Safety Evaluation for Browns Ferry that BTP 8-8 provides the staff with guidance for reviewing applications proposing a permanent TS change to extend a DG CT beyond 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Therefore, it appears the NRC staff utilized BTP 8-8 during its review of Browns Ferrys application. Comanche Peak meets the provisions of BTP 8-8 in that each unit can be placed in cold shutdown using the installed APDGs.

3. Duke Energy Catawba Nuclear Station, Units 1 and 2 and McGuire Nuclear Station, Units 1 and 2: Application dated May 2, 2017 (ADAMS Accession No. ML17122A116); McGuire NRC Safety Evaluation dated June 28, 2019 (ADAMS Accession No. ML19126A030); Catawba NRC Safety Evaluation dated August 27, 2019 (ADAMS Accession No. ML19212A655).

Similar to Duke Energy, Vistra OpCo chose to request a TS 3.8.1 CT extension to 14 days for an inoperable DG. The NRC also mentioned in its Safety Evaluation for Browns Ferry that BTP 8-8 provides the staff with guidance for reviewing applications proposing a permanent TS change to extend a DG CT beyond 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Therefore, it appears the NRC staff utilized BTP 8-8 during its review of Browns Ferrys application. Comanche Peak meets the provisions of BTP 8-8 in that each unit can be placed in cold shutdown using the installed APDGs.

4. Comanche Peak has had four license amendments issued with extended Completion Times for TS 3.8.1 with an inoperable offsite circuit or inoperable DG; License Amendment 152 issued on October 29, 2010 extended the Completion Time for an inoperable offsite power source from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. (ADAMS Accession No. ML102810130)

License Amendment 160 issued on September 18, 2013 extended the Completion Time for an inoperable offsite power source twice from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. (ADAMS Accession No. ML13232A143)

License Amendment 164 issued on February 24, 2015 extended the Completion Time for an inoperable offsite power source from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. (ADAMS Accession No. ML15008A133)

License Amendment 178 issued on February 12, 2021 extended the Completion Time for an inoperable DG from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 8 days. (ADAMS Accession No. ML21015A212)

Enclosure to TXX-23045 Page 30 of 33 In each of these instances Comanche Peak successfully implemented work planning and contingency actions that met the supplemental power requirement from BTP 8-8 to accomplish extended maintenance and/or modifications to improve Technical Specification 3.8.1, AC Sources --

Operating component reliability.

4.3 No Significant Hazards Consideration Determination Vistra OpCo has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment as discussed below:

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

Response: No The proposed change involves extending the TS CT for an inoperable DG at CPNPP. The DGs at both stations are safety related components which provide a backup electrical power supply to the onsite emergency power distribution system. The proposed change does not affect the design of the DGs, the operational characteristics or function of the DGs, the interfaces between the DGs and other plant systems or the reliability of the DGs. The DGs are not accident initiators; the DGs are designed to mitigate the consequences of previously evaluated accidents including a loss of offsite power. Extending the CT for a single DG would not affect the previously evaluated accidents since the remaining DGs supporting the redundant engineered safety feature systems would continue to be available to perform the accident mitigation functions. Thus, allowing a DG to be inoperable for 14 days for performance of maintenance or testing does not increase the probability of a previously evaluated accident. Deterministic and probabilistic risk assessment techniques evaluated the effect of the proposed TS change to extend the CT for an inoperable DG on the availability of an electrical power supply to the plant emergency safeguards feature systems. There is a small incremental risk associated with continued operation for 14 days with one DG inoperable; however, the calculated impact provides risk metrics consistent with the acceptance guidelines contained in Regulatory Guides 1.177 and 1.174.

The remaining operable DGs and paths are adequate to supply electrical power to the onsite emergency power distribution system. A DG is required to operate only if both offsite power sources fail and there is an event which requires operation of the plant engineered safety features such as a design basis accident. The probability of a design basis accident occurring during this period is low. The consequences of previously evaluated accidents will remain the same during the proposed 14-day CT as during the current 72-hour CT. The ability of the remaining TS required DGs to mitigate the consequences of an accident will not be affected since no additional failures are postulated while equipment is inoperable within the TS CT.

Enclosure to TXX-23045 Page 31 of 33 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 change involves extending the TS CT for an inoperable DG at CPNPP. The proposed change does not involve a change in the CPNPP plant design, plant configuration, system operation or procedures involved with the DGs. The proposed change allows a DG to be inoperable for additional time.

Equipment will be operated in the same configuration and manner as currently designed in accordance with operating procedures. The functional demands on credited equipment are unchanged. There are no new failure modes or mechanisms created due to plant operation for an extended period to perform DG maintenance or testing. Extended operation with an inoperable DG does not involve any modification to the operational limits or physical design of plant systems. There are no new accident precursors generated due to the extended CT.

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

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

Response: No The proposed change involves extending the TS CT for an inoperable DG at CPNPP. Currently, if an inoperable DG is not restored to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , TS 3.8.1, requires the units to be in Mode 3 (Hot Standby) within a CT of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and to be in Mode 5 (Cold Shutdown) within a CT of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The proposed TS change will allow steady state plant operation at 100 percent power for 14 days for performance of DG planned reliability improvements and preventive and corrective maintenance.

Deterministic and probabilistic risk assessment techniques evaluated the effect of the proposed TS change to extend the CT for an inoperable DG on the availability of an electrical power supply to the plant emergency safety feature systems. These assessments concluded that the proposed TS change does not involve a significant increase in the risk of power supply unavailability.

The DGs continue to meet their design requirements; there is no reduction in capability or change in design configuration. The DG response to loss of offsite power, loss of coolant accident, station blackout or fire scenarios is not changed by this proposed amendment; there is no change to the DG operating parameters. In the extended CT, as in the existing CT, the remaining operable DGs and paths are adequate to supply electrical power to the onsite emergency

Enclosure to TXX-23045 Page 32 of 33 power distribution system. The proposed change to extend the CT for an inoperable DG does not alter a design basis safety limit; therefore, it does not significantly reduce the margin of safety. The DGs will continue to operate in accordance with the existing design and regulatory requirements.

The proposed TS change (the inoperable DG CT extension) does not alter the plant design or change the assumptions contained in the safety analyses. The standby AC power system is designed with sufficient redundancy such that a DG may be removed from service for maintenance or testing. The remaining DGs are capable of carrying sufficient electrical loads to satisfy the Final Safety Analysis Report requirements for accident mitigation or unit safe shutdown. The proposed change does not impact the redundancy or availability requirements of offsite power circuits or change the ability of the plant to cope with a station blackout.

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

Based on the above evaluations, Vistra OpCo concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c) and, accordingly, a finding of no significant hazards consideration is justified.

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

5.0 ENVIRONMENTAL CONSIDERATION

S Vistra OpCo has determined that the proposed amendment would change requirements with respect to the installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amount of effluent that may be released offsite, or (iii) a significant increase in the individual or cumulative occupational radiation exposure. Accordingly, the proposed change meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), an environmental assessment of the proposed change is not required.

Enclosure to TXX-23045 Page 33 of 33

6.0 REFERENCES

1.

NUREG-0800, Branch Technical Position 8-8, Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions, U.S. Nuclear Regulatory Commission, February 2012.

2.

Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 2, U.S. Nuclear Regulatory Commission, May 2011.

3.

Regulatory Guide 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications, Revision 1, U.S. Nuclear Regulatory Commission, May 2011.

4.

Federal Register, Volume 51, p. 30028, Safety Goals for the Operations of Nuclear Power Plants; Policy Statement, Nuclear Regulatory Commission, August 21, 1986.

5.

Federal Register, Volume 60, p. 42622, Use of Probabilistic Risk Assessment Methods in Nuclear Regulatory Activities; Final Policy Statement, Nuclear Regulatory Commission, August 16, 1995.

6.

NUMARC 87-00, Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors, Revision 1, Nuclear Management and Resources Council, Inc., August 1991.

7.

Regulatory Guide 1.155, Station Blackout, Revision 0, U.S. Nuclear Regulatory Commission, August 1988.

8.

NUREG-1855, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking, Revision 1, U.S. Nuclear Regulatory Commission, March 2013.

9.

Generic Letter 80-30, Clarification of the Term Operable as It Applies to Single Failure Criterion for Safety Systems Required by TS (Generic Letter 80-30), U.S. Nuclear Regulatory Commission, April 1980.

10.

COMANCHE PEAK NUCLEAR POWER PLANT, UNIT NOS. 1 AND 2 -

ISSUANCE OF AMENDMENT NOS. 183 AND 183 REGARDING THE ADOPTION OF TECHNICAL SPECIFICATIONS TASK FORCE TRAVELER TSTF-505, REVISION 2 (EPID L-2021-LLA-0085) August 22, 2022 (ML22192A007)

EnclosuretoTXX23045 Aachment1 TechnicalSpeci"caonPages

AC Sources -- Operating 3.8.1 ACTIONS (continued)

COMANCHE PEAK - UNITS 1 AND 2 3.8-4 CONDITION REQUIRED ACTION COMPLETION TIME AND B.4 Restore DG to OPERABLE status. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition B entry 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months concurrent with unavailability of APDG OR In accordance with the Risk Informed Completion Time Program C. Two required offsite circuits inoperable.

C.1 --------------------NOTE--------------------

In MODES 1, 2 and 3, the TDAFW pump is considered a required redundant feature.

Declare required feature(s) inoperable when its redundant required feature(s) is inoperable.

AND C.2 Restore one required offsite circuit to OPERABLE status.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from discovery of Condition C concurrent with inoperability of redundant required features 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk Informed Completion Time Program Amendment No. 178, 183 AND 14 Days

AC Sources -- Operating 3.8.1 ACTIONS (continued)

COMANCHE PEAK - UNITS 1 AND 2 3.8-4 CONDITION REQUIRED ACTION COMPLETION TIME AND B.4 Restore DG to OPERABLE status. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition B entry 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months concurrent with unavailability of APDG OR In accordance with the Risk Informed Completion Time Program C. Two required offsite circuits inoperable.

C.1 --------------------NOTE--------------------

In MODES 1, 2 and 3, the TDAFW pump is considered a required redundant feature.

Declare required feature(s) inoperable when its redundant required feature(s) is inoperable.

AND C.2 Restore one required offsite circuit to OPERABLE status.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from discovery of Condition C concurrent with inoperability of redundant required features 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk Informed Completion Time Program Amendment No. 178, 183 AND 14 Days

EnclosuretoTXX23045 Aachment2 TechnicalSpeci"caonBasesPages (ForInformaonOnly)

AC Sources - Operating B 3.8.1 COMANCHE PEAK - UNITS 1 AND 2 B 3.8-1 Revision 85 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources - Operating BASES BACKGROUND The unit Class 1E AC Electrical Power Distribution System AC sources consist of the offsite power sources (preferred power source, and alternate),

and the onsite standby emergency power sources (Train A and Train B diesel generators (DGs)). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The onsite Class 1E AC Distribution System is divided into redundant load groups (trains) so that the loss of any one group does not prevent the minimum safety functions from being performed. Each train has connections to two offsite power sources and a dedicated DG.

Offsite power is supplied to the plant switchyards from the transmission network by seven 345 KV and two 138 KV transmission lines. From the switchyards, two electrically and physically separated circuits provide AC power, through step down startup transformers, to the 6.9 kV ESF buses. A detailed description of the offsite power network and the circuits to the Class 1E ESF buses is found in the FSAR, Chapter 8 (Ref. 2).

An offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network buses at plant switchyards to the onsite Class 1E ESF buses.

Certain required unit loads are started and/or returned to service in a predetermined sequence in order to prevent overloading the transformer supplying offsite power to the onsite Class 1E Distribution System. Within 2 minutes after the initiating signal is received, all automatic and permanently connected loads needed to recover the unit or maintain it in a safe condition are returned to service when the bus is energized by the load sequencer.

The onsite standby power source for each 6.9 kV ESF bus is a dedicated DG. DGs 1EG1, 1EG2, 2EG1 and 2EG2 are dedicated to ESF buses 1EA1, 1EA2, 2EA1 and 2EA2 respectively. The DG starts automatically on a safety injection (SI) signal or associated bus undervoltage.

If the Diesel Generator voltage exceeds the minimum or maximum voltage limits for steady state operation, except for allowed transients (less than 3 (continued)

Insert A

INSERT A The onsite system for each unit may be connected to an Alternate Power Diesel Generator (APDG), Ref. FSAR 8.3.1.1.1.3. The APDG may be connected to either 6.9 kV Class 1E bus. The APDG consists of 3000 kW, non-safety related, commercial grade DGs. Manual action is required to align the APDG to the selected 6.9 kV Class 1E bus. The APDG is available to support extended Completion Times in the event of an inoperable DG as well as provide defense-in-depth as an AC source to mitigate a Station Blackout (SBO). The APDGs are normally not connected to the Class 1E AC Distribution System and are connected to a Class 1E bus when required for supplemental power to the affected unit.

AC Sources - Operating B 3.8.1 BASES COMANCHE PEAK - UNITS 1 AND 2 B 3.8-10 Revision 85 ACTIONS B.3.1 and B.3.2 (continued) the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months COMPLETION TIME for TS 3.8.1, Required Actions B 3.1 and B 3.2 does not apply with respect to the unaffected Unit or its DGs.

Required Action B.3.1 provides an allowance to avoid unnecessary testing of the OPERABLE DG. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on the other DG, the other DG would be declared inoperable upon discovery and Condition E of LCO 3.8.1 would be entered. Once the failure is repaired, the common cause failure no longer exists, and Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG, performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of that DG.

In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the applicable plant procedures will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition B.

According to Generic Letter 84-15 (Ref. 7), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable to confirm that the OPERABLE DG is not affected by the same problem as the inoperable DG.

During performance of surveillance activities as a requirement for ACTION statements, the air-roll test shall not be performed.

B.4.1 According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period. Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.

(continued)

Insert B

INSERT B NUREG-800, BTP 8-8, "Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions," provides the regulatory framework to approve a permanent license amendment for a single inoperable DG up 14 days in order to perform online maintenance. This process establishes a 14 day Completion Time for TS LCO 3.8.1, Required Action B.4.

Prior to a planned entry into Required Action B.4 the following actions will be taken;

1. The associated Unit's Alternate Power Diesel Generator (APDG) will be verified in standby, ready to align to a pre-determined 6.9 kV Class 1E bus, and with fuel oil level at approximately 100%.

2. Maintenance support will be established such that the APDG fuel oil level is checked and refilled to ensure level does not drop below 25% while the APDG is providing supplemental power.

3. Guarded Equipment postings and barriers will be placed to control access for protected equipment;

a. Opposite train safety related components (e.g, AFW, CCP, SIP, RHRP, CCWP, SSWP, EDG, 6.9 kV Class 1E Switchgear, and Safety Chilled Water).

b. 345 kV and 138 kV switchyards and relay houses.

c. Startup transformers in service for 6.9 kV Class 1E preferred and alternate offsite sources.

4. Operations Control Room staff will review actions to supply the pre-determined 6.9 kV Class 1E bus from the APDG.

While operating in Required Action B.4 the following actions will be taken;

1. Operations will designate an operator to align and start the APDG, if needed each shift.

2. The designated APDG operator will review the procedure for aligning and starting the APDG at the beginning of each shift.

3. The availability of the APDG will be verified each shift.

4. Switchyard access will be limited such that offsite power sources are not challenged.

Unavailability of the APDG while operating in Required Action B.4; If the APDG becomes unavailable during a Required Action B.4 entry a one time allowance, per entry, is provided to restore the required APDG to available status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If this allowance is utilized, depending on the circumstances, preparations for utilization of the RICT program should begin and be completed prior to the expiration of the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance.

AC Sources - Operating B 3.8.1 BASES COMANCHE PEAK - UNITS 1 AND 2 B 3.8-11 Revision 85 ACTIONS (continued) B.4.2 The COMPLETION TIME for restoring the inoperable SSWS train to OPERABLE status can be extended to 8 days, on a one time basis for SSWS 2-02 (Train B) pump replacement during Unit 2 Cycle19. This one-time change regains reliability margin for Unit 2, Train B SSWS. The 8 day completion time is based on a deterministic evaluation supplemented with risk insights.

C.1 and C.2 Required Action C.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref. 6) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is appropriate. These features are powered from redundant AC safety trains. This includes the motor driven auxiliary feedwater pumps and the TDAFW pump which must be available for mitigation of a Feedwater line break. Single train systems, other than the turbine driven auxiliary feedwater pump, are not included.

The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:

a.

All required offsite circuits are inoperable; and b.

A required feature is inoperable.

If at any time during the existence of Condition C (two offsite circuits inoperable) a required feature becomes inoperable, this Completion Time begins to be tracked.

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program. This level of degradation means that the offsite electrical power system does not have the capability to effect a safe (continued)

AC Sources - Operating B 3.8.1 BASES (continued)

COMANCHE PEAK - UNITS 1 AND 2 B 3.8-29 Revision 85 REFERENCES 1.

10 CFR 50, Appendix A, GDC 17.

2.

FSAR, Chapter 8.

3.

Regulatory Guide 1.9 Rev 3, July 1993.

4.

FSAR, Chapter 6.

5.

FSAR, Chapter 15.

6.

Regulatory Guide 1.93, Rev. 0, December 1974.

7.

Generic Letter 84-15, "Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability," July 2, 1984.

8.

10 CFR 50, Appendix A, GDC 18.

9.

Regulatory Guide 1.108, Rev. 1, August 1977.

10.

Regulatory Guide 1.137, January 1978.

11.

ASME Code for Operation and Maintenance of Nuclear Power Plants.

12.

IEEE Standard 308-1974.

13.

IEEE Standard 387-1977 14.

Generic Letter 94-01, Removal of Accelerated Testing and Special Reporting Requirements for Emergency Diesel Generators, May 31, 1994.

15.

ANSI C84.1 16.

NUREG-800, BTP 8-8, "Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions,"

EnclosuretoTXX23045 Aachment3 CPNPPSystemFigures (ForInformaonOnly)

8080 8030 8020 W11 W10 E10 8645 W9 8079 8081 8029 8031 8021 8019 8644 8646 E8 8041 8039 8090 W7 8089 8091 7980 7970 W6 E6 7979 7981 7971 7969 8050 W5 8049 8051 8650 E4 8651 8649 8010 8000 W3 8009 8011 8001 7999 E3 8070 W2 8069 8071 8060 E1 8061 8059 WEST BUS EAST BUS 345 KV Switchyard 8075 8076 8074 8002 8022 E11 14731 14729 14730 14739 14741 14740 14744 14745 14746 14754 14755 14756 These breakers controlled by CPNPP Iso Phase Bus Duct Cooling PT Flex Link Rigid Link Bus Conn Gen Flex Link Flex Conn Aux Bus Lower Link Aux Bus Upper Link Aux Bus Link Flex Conn Flex Conn Generator Line Bushing Box Neutral Bushing Neutral Bushing Box Neutral Grounding Transformer Y

X 2ST 2A2-2, 2A4-2, XA1-2 2MT1 2MT2 2UT Y

X 2A1-2, 2A3-2 2A2-1, 2A4-1 2A1-1, 2A3-1 Potential Transformers Y

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X 1A2-1, 1A4-1 1A1-1, 1A3-1 Unit 2 Main Generator Unit 1 Main Generator Transformer

1 25 kV Loop 7050 7030 7040 7029 7031 7041 7039 7022 7020 7019 7021 7052 Transformer

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EnclosuretoTXX23045 Aachment4 CPNPPWorkManagementPhilosophy

ATTACHMENT 8.C PAGE 1 OF 1 WORK MANAGEMENT PHILOSOPHY CPNPP STATION INSTRUCTION MANUAL INSTRUCTION NO.

STI-604.02 MAINTENANCE RISK ASSESSMENT REVISION NO. 3 PAGE 43 OF 95 INFORMATION USE

1.0 Ownership

1.1 Each organization in the work process exhibits strong ownership of its part of the process.

1.2 Each organization actively participates in the process, adding its respective value to the products in a timely manner.

1.3 Each organization actively supports the schedule.

1.4 Each organization identifies and works to resolve process implementation problems.

1.5 Feedback is sought and provided at each step of the process and is used as a basis for improvement.

1.6 Each Organization reviews and incorporates Operating Experience within their role in the Work Management process per IER-21-04 2.0 Teamwork Equals Shared Ownership:

2.1 There is shared ownership of the results of the work process across the organization, not just within the line work control organization or in maintenance. This does not preclude the need for clearly defined roles and responsibilities.

2.2 The organization works together to make it happen and does not tolerate excuses for commitments not being met.

3.0 Emergent Work:

3.1 There are clear, objective guidelines for the prioritization of work.

3.2 Emergent work is responded to in an orderly fashion, not in a reactive fashion.

3.3 The schedule is protected from the effects of emergent work through supplemental activities such as those performed by the PROMPT team.

3.4 Management periodically audits the emergent work policy to ensure compliance.

4.0 Station Management Fosters Confidence in the Work Management Process:

4.1 Trusting the process to work and not overreacting to short-term trends in the numbers.

4.2 Not overriding the process by placing inappropriate high priority on pet work orders that do not meet the prioritization criteria.

4.3 Holding the organization accountable to support and work through the process.

4.4 Being responsive in resolving identified process or implementation problems.

EnclosuretoTXX23045 Aachment5 14dayCompleonTimeEntry

14-day Completion Time Entry NUREG-800, BTP 8-8, "Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions," provides the regulatory framework to approve a permanent license amendment for a single inoperable DG up 14 days in order to perform online maintenance. This process establishes a 14-day Completion Time for TS LCO 3.8.1, Required Action B.4.

Prior to a planned entry into Required Action B.4 the following actions will be taken:

1. The associated Unit's Alternate Power Generator Djesel (APDG) will be verified in standby, ready to align to a pre-determined 6.9 kV Class 1E bus, and with fuel oil level at approximately 100%.

2. Maintenance support will be established such that the APDG fuel oil level is checked and refilled to ensure level does not drop below 25% while the APDG is providing supplemental power.

3. Guarded Equipment postings and barriers will be placed to control access for protected equipment:

a. Opposite train safety related components (e.g., AFW, CCP, SIP, RHRP, CCWP, SSWP, EDG, 6.9 kV Class 1E Switchgear, and Safety Chilled Water).

b. 345 kV and 138 kV switchyards and relay houses.

c. Startup transformers in service for 6.9 kV Class 1E preferred and alternate offsite sources.

4. Operations Control Room staff will review actions to supply the pre-determined 6.9 kV Class 1E bus from the APDG.

While operating in Required Action B.4 the following actions will be taken:

1. Operations will designate an operator to align and start the APDG, if needed each shift.

2. The designated APDG operator will review the procedure for aligning and starting the APDG at the beginning of each shift.

3. The Availability of the APDG will be verified each shift.

4. Switchyard access will be limited such that offsite power sources are not challenged.

Unavailability of the APDG while operating in Required Action B.4; If the APDG becomes unavailable during a Required Action B.4 entry a one time allowance, per entry, is provided to restore the required APDG to available status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If this allowance is utilized, depending on the circumstances, preparations for utilization of the RICT program should begin and be completed prior to the expiration of the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance.

EnclosuretoTXX23045 Aachment6 BaselineAverageAnnualCDF/LERF

Baseline Average Annual CDF/LERF A6 PRA Model Capability and Risk Insights The risk assessment of the proposed CT extension is based on quantitative models for Internal Events, Internal Flooding and Internal Fire, and qualitative assessments for external hazards. The CPNPP models meet the scope and quality requirements of RG 1.200, Revision 2 An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities (Reference 7).

CPNPP procedures are in place for controlling and updating the models, when appropriate, and for assuring that the models represent the as-built, as-operated plant. The conclusion, therefore, is that the CPNPP PRA models are acceptable for use in providing supplemental risk information for applications, including assessment of proposed TS amendments.

As part of the implementation of the Risk-Informed Extended Completion Time application (Reference 10), Comanche Peak has implemented several procedural controls that are now used as general business practices. These practices include the configuration control of the PRA models to provide assurance that plant modifications and procedure changes that potentially affect the PRA models are identified and incorporated, as appropriate, into the PRA models to ensure that the models, including the Configuration Risk Management Tools, reflect the as-built, as-operated and maintained plant. Other practices include the consideration of Risk Management Actions to minimize and manage the risks associated with plant maintenance activities (see Section A6.5 for more information).

The PRA analysis and calculation for the proposed COMPLETION TIME are shown below. The results show that the risk significance from extending the proposed COMPLETION TIME for an inoperable Emergency Diesel Generator train from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days is in accordance with applicable regulatory guidance. The total CDF and LERF values are consistent with thresholds referenced in NRC RG 1.174, Revision 2 (Reference 3) for consideration in review of licensing changes (i.e., CDF less than 1E-4 per year and LERF less than 1E-5 per year). The risk impact results, when considered with the unquantified benefits of implementing effective risk reduction measures, are consistent with thresholds referenced in RG 1.177, Revision 1 (Reference 4). Note that such measures reduce the sources of increased risk, but they are not explicitly credited in the quantitative risk evaluation.

The CPNPP PRA models do not include quantitative (or qualitative) credit for any FLEX or portable equipment.

A6.1 Technical Adequacy of the PRA The CPNPP PRA model is sufficiently robust and suitable for use in risk informed applications such as for regulatory decision making, including the Risk-Informed Extended Completion Time application (TSTF-425, R2), as evidenced by the NRCs Safety Evaluation (Reference 10). The peer reviews that have been conducted and the resolution of findings from those reviews demonstrate that the internal events,

internal flooding, and fire models of the PRA have been performed in a technically correct manner. The assumptions and approximations used in development of the PRA have also been reviewed and are appropriate for this application.

CPNPP employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for Comanche Peak. This approach includes both a proceduralized PRA maintenance process and the use of self-assessments, independent reviews, and independent peer reviews. Results from peer reviews are documented and addressed; F&O (Facts and Observations) resolutions have been incorporated to establish technical adequacy of the CPNPP PRA model to address the risk impact of the proposed license amendment. No changes to the PRA were required for use in the TS change evaluation. Finding level Facts and Observations (F&Os) not met at Category II have been closed by CPNPP with PRA documents and independent review where applicable. Three Supporting Requirements (SRs) (LE-C11, IFEV-A6 and IFSN-A6) met at Capability Category I had no associated finding level F&O and review determined these did not impact risk results relative to the subject application.

PRA Acceptability Internal Events and Internal Flooding Hazards This Technical Specification change evaluation includes results from the CPNPP peer reviewed, plant specific baseline PRA model which quantifies Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) due to internal events, including internal flooding, at power. The CPNPP model maintenance process ensures that the PRA model used in this application reflects the as-built, as operated plant for each of the two units.

Following a model upgrade and self-assessment, the Comanche Peak PRA was subject to a PWROG full scope peer review in March 2011 in accordance with the 2009 version of the PRA Standard (ASME/ANS RA-Sa-2009). Among the 308 applicable Supporting Requirements (SRs), 94% of SRs met Capability Category II or higher. Finding and Suggestion F&Os, including those associated with Capability Category I or not met SRs, were fully addressed and documented. Subsequent independent reviews confirmed resolutions and closure were adequate with only one suggestion level F&O remaining open. The safety evaluation of license amendment No. 156 for Comanche Peaks TSTF 425 surveillance Frequency Control Program provided a confirmatory review of the March 2011 peer review F&O resolutions relative to that application. No PRA upgrades as defined in the PRA standard have been made to the internal events model since the conduct of the peer review.

In 2018, an independent assessment was performed to review actions taken by CPNPP to close out the open internal events F&Os. The assessment followed the process documented in Appendix C of NEI 05-04 (NEI 05-04 Revision 2). All finding level internal events F&O dispositions and identified suggestion F&Os were determined to have been adequately addressed and are now considered CLOSED and no longer relevant to the PRA model. The current PRA model, CPNPP MOR 5,

has met all Supporting Requirements judged to have significance to this LAR at Capability Category II or better.

The current baseline CDF and LERF for the internal events and internal flooding model are provided in Table A6.1.

Fire Hazards This Technical Specification change evaluation includes results from the 2019 CPNPP peer reviewed, plant specific PRA model to quantify Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) due to fire hazards, at power. The Fire PRA model is consistent with NUREG/CR 6850 methodology with no exceptions. The peer review indicated data, methodologies and fire risk models were appropriate with no unapproved methods (UAMs). Since the peer review, the Comanche Peak fire PRA has been revised to incorporate updated industry information and applicable FAQs. The current Comanche Peak Fire PRA model has been developed, documented and reviewed with reference to RG 1.200, Revision 2, Capability Category II standards.

Following a model revision, an independent assessment was performed in 2018 to review actions taken by CPNPP to close out the open fire F&Os. The assessment followed the process documented in Appendix C of NEI 05-04. All finding level fire F&O dispositions were determined to have been adequately addressed and are now considered CLOSED and no longer relevant to the PRA model.

The current baseline CDF and LERF for the internal fire are provided the Table A6.1.

Seismic Hazards For seismic events, CPNPP is considered to be in an area of low seismicity. The potential effects from seismic events for the Technical Specification change were considered with reference to the seismic PRA margin analysis was created in support of the Individual Plant Evaluation of External Events (IPEEE). As a reduced scope plant, the IPEEE Seismic analysis used a margin approach that assumed a LOOP and Very Small Break LOCA in a seismic event. Since the Emergency Diesel Generator system and its supports are in Category I seismic structures, they are assumed to not be damaged (total failure) in the seismic event. The change in risk associated with a train of Emergency Diesel Generator being OOS for the extended CT is equivalent to the change in risk seen from the internal events model for random failures. In addition, the frequency of a seismic occurrence over the extended CT is considered small, and when considering that a train of safety related equipment would remain available, the overall change in risk due to the extended CT can be considered small. Updated seismic hazard information was reviewed and determined the IPEEE conclusion, that there are no plant-specific vulnerabilities to seismic events at CPNPP, is still appropriate and bounds the expected current day seismic risk impacts for CPNPP.

Other External Hazards A qualitative review was documented in Engineering Evaluation to evaluate other external events for risk impact associated with the requested extension to the Emergency Diesel Generator CT. These assessments considered high winds, external floods, external fire, and other transportation and nearby facility accidents with reference to the analyses done in support of the IPEEE.

IPEEE results were considered as part of the qualitative evaluation for the extended CT. The recently developed high wind PRA provides quantitative results and walkdown insights that confirm the IPEEE insights and conclusions.

Scenarios with potential impact from high wind and tornado events were reviewed; results indicate that the bounding case of core damage risk from a tornado strike at CPNPP is quite small. The dominant sequences do not involve tornado-induced failures of plant structures or equipment. This is explained by the fact that nearly all risk significant equipment is well protected within Seismic Category I structures which are designed to withstand tornadoes up to the design basis tornado. It should be noted that a potential equipment vulnerability identified in the IPEEE (TDAFW pump exhaust stack) has been evaluated by the plant and found to not cause a loss of function following a high wind generated missile. Given the relatively low likelihood of a tornado occurring over the time frame of the extended CT and the availability of a train of equipment (including the restrictions identified in Section 3.14 of this submittal), the change in tornado risk as discussed above is considered to be small. The IPEEE concluded that the significant contribution from this hazard was due to the lower range of high wind events. The likelihood of a tornado strike at CPNPP was estimated to be ~5E-04 annually. The likelihood of a high wind event to occur during the extended CT duration is relatively small (~1.9E-05, IPEEE) for a wind event during the 14-day CT) and major mitigating systems are not directly affected by the wind event. Individual qualitative assessments from the documented evaluation of other external hazards show changes in risk are small and do not impact the overall conclusions of the quantitative risk assessment for internal events, internal flooding and fire.

A6.2 PRA Uncertainty Evaluations The review of generic and plant specific sources of uncertainty for the baseline models has been performed. The sensitivity studies were adequate to address uncertainty associated with this application, including the uncertainty evaluated with respect to room heat-up calculations. Parametric uncertainties were examined using standard statistical error propagation techniques and CDF and LERF deviations from the point estimates remained within an acceptance criterion of 10 percent. For uncertainty related to completeness, the proposed changes do not introduce any application-specific sources of uncertainty, and those for the baseline model have been minimized through the use of consensus modeling. The calculations include internal events, internal flood and fire, at power. The proposed configuration is only applicable at-power and other hazard groups (seismic, external events) are unchanged from the Individual Plant Examinations.

A6.3 Configuration Risk Management Program A proceduralized process is established to assess the risk associated with both planned and unplanned work activities. The objective is to ensure that the risk impact of out-of-service equipment is evaluated prior to performing any maintenance activity. As stated in RG 1.177 (Section 2.3) refers to the key attribute of the program as the capability [] to uncover risk significant plant equipment outage configurations in a timely manner during normal plant operation. This program is intended to complement the analysis in the previous section to address the limitation of not being able to identify all possible risk significant plant configurations.

Programs and procedures are in place at CPNPP which serve to address this objective.

CPNPP has a Configuration Risk Management program which has the characteristics of the Model Configuration Risk Management Program described in RG 1.177 and which was previously approved for risk informed In-Service Inspection and for the Surveillance Test Frequency Control Program. Its description has been incorporated into plant Technical Specifications. In addition, CPNPP has committed to NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,. CPNPP has implemented process improvements to comply with Revision 4A of NUMARC 93-01.

To avoid or reduce the potential for risk-significant configurations from either emergent or planned work, CPNPP has put in place a set of administrative guidelines that go beyond the limitations set forth in the plant TS. These guidelines control configuration risk by assessing the risk impact of equipment out-of-service during all modes of operation to assure that the plant is always being operated within acceptable risk guidelines.

CPNPP employs a conservative approach to at-power maintenance. The weekly schedules are train/channel based and prohibit the scheduling of opposite train activities without additional review, approvals and/or risk reduction actions. The assessment process further minimizes risk by restricting the number and combination of systems/trains allowed to be simultaneously unavailable for scheduled work. Unplanned or emergent work activities are factored into the plants actual and projected condition, and the level of risk is evaluated. Based on the result of this evaluation, decisions are made pertaining to what actions, if any, are required to achieve an acceptable level of risk (component restoration or invoking risk reduction measures). The unplanned or emergent work activities are also evaluated to determine impacts on planned activities and the effect the combinations would have on risk.

Currently, CPNPP uses the PhoenixRM software to perform online risk assessment.

All PRA components are represented in PhoenixRM with the ability to take one or multiple components out-of-service. After the activities have been added (i.e.,

components taken out-of-service) the model will be quantified to calculate the CDF and LERF for that specific configuration. The risk is then compared to preset baseline values and the risk colors are assigned (by PhoenixRM) based on preset

threshold values. As the risk is increased, the requirement for management approval is raised and non-quantifiable risk reduction measures are implemented. External events are evaluated qualitatively to determine their impact on the configuration risk.

In summary, the CRMP process is performed for all activities that affect PRA components, initiating events, or recoveries. The Work Control Group uses the weekly schedule to calculate the plant risk for the week on an activity basis. Entry into the proposed CT would be added to the weekly schedule and the risk for the activity would be calculated. The resulting weekly risk assessment would then be reviewed, and appropriate management approval obtained. The process described above would apply for any emergent activities. The risk is assessed prior to the emergent activity being worked. The risk is calculated and scheduled activities may be moved to a later date or equipment put back in-service to ensure an acceptable level of risk. Again, changes to the risk assessment would be reviewed and appropriate management approval obtained. CPNPP has established an effective process for CRMP that is consistent with RG 1.177, Section 2.3.7 A6.4 Baseline Core Damage Frequency (CDF) and Large Early Release Frequency (LERF)

Table A6.4.1 Baseline PRA Model Average Annual CDF/LERF1,2,3 Hazard Unit 1 Unit 2 CDF (per year)

LERF (per year)

CDF (per year)

LERF (per year)

Internal Events and Internal Flooding 1.13E-06 1.06E-07 1.16E-06 1.08E-07 Internal Fire 4.20E-05 5.72E-06 4.23E-05 5.69E-06 Total 4.31E-05 5.83E-06 4.35E-05 5.80E-06 Table Notes:

1. The contribution of High Winds and Seismic to baseline CDF / LERF values was evaluated qualitatively; risk from this hazard is small compared to other events based on plant design and low likelihood of occurrence of a significant wind event due to the time frame of the extended CT and prior confirmation of the long-range forecast.

2. Truncations are based on individual Models of Record.

3. These values will be updated as the PRA Models of Record are updated to include such changes at the proposed EDG extended Completion Time

EnclosuretoTXX23045 Aachment7 ICCDPandICLERPfor14dayCompleonTimefor oneEmergencyDieselGeneratorInoperable

ICCDP and ICLERP for 14-day Completion Time for one Inoperable Emergency Diesel Generator Threshold values of ICCDP and ICLERP from RG 1.177, ICCDP < 1E-05 and ICLERP < 1E-06, can be considered in this evaluation of an acceptable level of change in risk for the proposed CT extension. This threshold is appropriate given that effective compensatory measures are in place to reduce the overall risk increases. Further, this PRA evaluation is extended to apply thresholds for CDF and ICCDP < 1.0E-06 and LERF and ICLERP < 1.0E-07 as described in RG 1.177 and RG 1.174. See Section A7.1 for more information of the calculation of the ICCDP and ICLERP values.

Table A7.1 represents Case IA (Unit 1 EDG OOS),

Table A7.2 represents case IIA (Unit 2 EDG OOS),

Table A7.3 represents Case IB (Unit 1 Opposite Unit EDG OOS), and Table A7.4 represents case IIB (Unit 2 Opposite Unit EDG OOS)

Table A7.2: Delta CDF and LERF, and ICCDP and ICLERP for Technical Specification Change CP2-MEDGEE-02 Results1 Unit 2 - Case IIA (CT = 14 days)

Hazards Delta CDF ICCDP2 Delta LERF ICLERP2 (per year)

(CT)

(per year)

(CT)

Internal Events and Internal Flooding 7.96E-07 7.96E-07 5.49E-08 5.49E-08 Internal Fire 1.36E-06 1.36E-06 1.27E-07 1.27E-07 Total 2.15E-06 2.15E-06 1.82E-07 1.82E-07 1 This information is obtained from the integrated model runs 2 Per RG 1.177, the ICCDP/LERP is equal to the delta CDF. The RG 1.174 metric for risk impact is the change in the average CDF/LERF (CDF/LERF) as a result of the change in licensing basis. (See Section A 7.1)

Table A7.1: Delta CDF and LERF, and ICCDP and ICLERP for Technical Specification Change CP1-MEDGEE-02 Results1 Unit 1 - Case IA (CT = 14 days)

Hazards Delta CDF ICCDP2 Delta LERF ICLERP2 (per year)

(CT)

(per year)

(CT)

Internal Events and Internal Flooding 7.60E-07 7.60E-07 5.33E-08 5.33E-08 Internal Fire 1.45E-06 1.45E-06 1.37E-07 1.37E-07 Total 2.21E-06 2.21E-06 1.90E-07 1.90E-07 1 This information is obtained from the integrated model runs 2 Per RG 1.177, the ICCDP/LERP is equal to the delta CDF. The RG 1.174 metric for risk impact is the change in the average CDF/LERF (CDF/LERF), as a result of the change in licensing basis. (See Section A 7.1)

Table A7.3: Delta CDF and LERF, and ICCDP and ICLERP for Technical Specification Change CP2-MEDGEE-02 (Opposite Unit) Results Unit 1 - Case IB (CT = 14 days)

Hazards Delta CDF ICCDP2 Delta LERF ICLERP2 (per year)

(CT)

(per year)

(CT)

Internal Events and Internal Flooding 1.74E-08 1.74E-08 3.48E-10 3.48E-10 Internal Fire 4.95E-08 4.95E-08 2.04E-09 2.04E-09 Total 6.69E-08 6.69E-08 2.39E-09 2.39E-09 1 This information is obtained from the integrated model runs 2 Per RG 1.177, the ICCDP/LERP is equal to the delta CDF. The RG 1.174 metric for risk impact is the change in the average CDF/LERF (CDF/LERF) as a result of the change in licensing basis. (See Section A 7.1)

Table A7.4: Delta CDF and LERF, and ICCDP and ICLERP for Technical Specification Change CP1-MEDGEE-02 (Opposite Unit) Results1 Unit 2 - Case IIB (CT = 14 days)

Hazards Delta CDF ICCDP2 Delta LERF ICLERP2 (per year)

(CT)

(per year)

(CT)

Internal Events and Internal Flooding 2.29E-09 2.29E-09 8.64E-11 8.64E-11 Internal Fire 4.07E-09 4.07E-09 5.37E-11 5.37E-11 Total 6.36E-09 6.36E-09 1.40E-10 1.40E-10 1 This information is obtained from the integrated model runs 2 Per RG 1.177, the ICCDP/LERP is equal to the delta CDF. The RG 1.174 metric for risk impact is the change in the average CDF/LERF (CDF/LERF) as a result of the change in licensing basis. (See Section A 7.1)

A 7.1 Calculation of incremental conditional core damage probability Assessing the risk impact associated with a permanent change to the plant licensing basis. The RG 1.174 metric for risk impact is the change in the average CDF (CDF),

as a result of the change in licensing basis.

Calculate the incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP) as follows:

ICCDP (or ICLERP) = [conditional CDF (or LERF) w/ subject equipment OOS and any other adjustments being credited] - [baseline CDF (or LERF) w/ no equipment unavailability] x desired duration of the NOED.

These values should be compared with guidance thresholds (ref. 1) of less than or equal to an ICCDP of 5E-7 and an ICLERP of 5E-8. These numerical guidance values are not pass-fail criteria.

First, calculate the revised CDF and the subsequent CDF. This method uses CCDP as equivalent to CDF. Note that LERF can be derived by substituting LERF for CDF.

Use the following equation:

CDF = ((CDFN

T0/365) + (CDFTMA * (365 - T0)/365)) - CDFBASE CDFN = CDF w/ component of interest OOS and other constraints as required T0 = duration for which constraints will be applied. If no constraints are applied, this is the duration for which the component will be taken out of service with the revised CT CDFTMA = CDF w/ nothing OOS and test and maintenance adjusted so that total annual maintenance is constant, i.e. maintenance may be deferred from the T0 term but will occur at some other time in the year.

The hours used to determine the TMA frequency need to be increased by the fraction T0/365.

CDFBASE = Baseline CDF with average test and maintenance

v t e Letter Sequence Request
EPID:L-2023-LLA-0130, TSTF-505, TSTF-425 (Approved, Closed)
Initiation Request Acceptance Supplement Administration Questions 19 January 2024 2 February 2024 2 February 2024 Answers 4 March 2024 Results Approval Other:
MONTHYEAR2024-02-02 [Table View]

CP-202300293, (CPNPP) - License Amendment Request Proposing Changes to Technical Specifications to Extend the Allowed Outage Time for an Inoperable Emergency Diesel Generator from 72 Hours to 14 Days: Difference between revisions

Latest revision as of 05:42, 21 February 2026

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@@ Line 354: / Line 354: @@
 During a Design Bases Accident (DBA) all eight PPVS Supply Units and the twelve Non-ESF PPVS Exhaust Filter Units are de-energized. The four ESF PPVS Exhaust Filter Units are energized to maintain a negative pressure in the plant Radiologically Controlled Area (RCA), which includes the Auxiliary Building, the Fuel Building and both Unit Safeguards Buildings and limit the radioactive release to the atmosphere.
 The Uninterruptable Power Supply (UPS) HVAC System is required to maintain an indoor temperature no greater than 104&#xba;F in both the UPS distribution rooms (118VAC 1E Inverters and battery chargers) and AC Equipment Room during normal, upset (abnormal), or emergency modes of plant operation. The system provides 100% redundancy of safety related components to sustain a single active failure without loss of function and preclude common mode failures. The system is common to both units. Electrical power is normally aligned such that each unit is powered from a different unit 1E power.
-Normal room cooling is provided to each UPS and Distribution Room by a Room Fan Coil Unit supplied from the Safety Chilled Water System (CHS). The UPS and Distribution A\\C System can also provide room cooling during normal plant operations, or Black Out and Safety Injection conditions (Figure 8).
+Normal room cooling is provided to each UPS and Distribution Room by a Room Fan Coil Unit supplied from the Safety Chilled Water System (CHS). The UPS and Distribution A\C System can also provide room cooling during normal plant operations, or Black Out and Safety Injection conditions (Figure 8).
 Enclosure to TXX-23045 Page 27 of 33 3.17 Risk Informed Completion Time Front Stop CPNPP is approved to implement the RICT program. For TS 3.8.1 Condition B, Required Action B.4, 72 hours will be considered the front stop for cumulative risk tracking planning purposes. If the RICT program was utilized after entering Required Action B.4 for greater than the 14-day allowed outage time and the APDG was available for the entire duration of the first 14 days of the Required Action B.4 entry, then 14 days may be considered the front stop for cumulative risk tracking purposes.
@@ Line 894: / Line 894: @@
 PRIMARY PLANT VENTILATION SUPPLY EQUIPMENT TO AUXILIARY BUILDING AUXILIARY BUILDING VENTILATION EQUIPMENT R O OM SUPPLY FANS TO CONTAINMENT PURGE SYSTEM UNIT#2 TO AUXILIARY BUILDING TO FUEL TO TO HANDLING SAFEGUARDS SAFEGUARDS BUILDING BUILDING BUILDING UNIT#2 UNIT#1 PRIMARY PLANT SUPPLY AIR PLENUM PRIMARY PLANT SUPPLY AIR INTAKE PLENUM FRESH AIR INTAKE TO CONTAINMENT PURGE SYSTEM UNIT#1 PRIMARY PLANT VENTILATION SUPPLY UNITS TO tl2 PURGE SYSTEM UNIT#1 Figure 6
-PRIMARY PLANT VENTILATION EXHAUST EQUIPMENT VENT STACK RADIATION MONITORS PRIMARY PLANT VENTILATION EXHAUST UNITS TRAIN "A" FROM rol\\lIAl.t:l:-
+PRIMARY PLANT VENTILATION EXHAUST EQUIPMENT VENT STACK RADIATION MONITORS PRIMARY PLANT VENTILATION EXHAUST UNITS TRAIN "A" FROM rol\lIAl.t:l:-
 M&_fil PURGE SY.$
 UNIT#2 ---*

CP-202300293, (CPNPP) - License Amendment Request Proposing Changes to Technical Specifications to Extend the Allowed Outage Time for an Inoperable Emergency Diesel Generator from 72 Hours to 14 Days: Difference between revisions

Latest revision as of 05:42, 21 February 2026

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Subject:

Dear Sir or Madam:

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SUMMARY

3.0 TECHNICAL EVALUATION

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5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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