Text

Response to Second Round Request for Additional Information (Rais) for License Amendment Request to Adopt Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b
	ML21090A283
Person / Time
Site:	LaSalle
Issue date:	03/31/2021
From:	Demetrius Murray; Exelon Generation Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RS-21-040
	Download: ML21090A283 (44)
	v • d • e

4300 Winfield Road Warrenville, IL 60555 www.exeloncorp.com 10 CFR 50.90 RS-21-040 March 31, 2021 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 LaSalle County Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-11 and NPF-18 NRC Docket Nos. 50-373 and 50-374

Subject:

Response to Second Round Request for Additional Information (RAIs) for LaSalle License Amendment Request to Adopt Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times -

RITSTF Initiative 4b"

References:

1. Letter from D. Murray (Exelon Generation Company, LLC) to U.S. Nuclear Regulatory Commission, "Application to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b,' (EPID L-2020-LLA-0018)," dated January 31, 2020.

2. Letter from B. Vaidya (Project Manager, U.S Nuclear Regulatory Commission) to B. Hanson (Exelon Generation Company, LLC), "LaSalle County Station Unit 1 and 2 - Request for Additional Information for LaSalle License Amendment Request to Adopt Risk-Informed Completion Times TSTF-505, Revision 2, 'Provide Risk-Informed extended Completion Times -

RITSTF Initiative 4b' (EPID L-2020-LLA-0018)," dated September 3, 2020.

3. Letter from B. Vaidya (Project Manager, U.S Nuclear Regulatory Commission) to B. Hanson (Exelon Generation Company, LLC), "LaSalle County Station Unit 1 and 2 - Correction to Request for Additional Information Regarding License Amendment Request to Adopt TSTF-505, Revision 2, "Provide Risk-Informed extended Completion Times - RITSTF Initiative 4b' (EPID L-2020-LLA-0018)," dated September 16, 2020.

4. Letter from D. Murray (Exelon Generation Company, LLC), "LaSalle County Station, Unit Nos. 1 And 2 - Response to Request for Additional Information Regarding License Amendment Request to Adopt TSTF-505, Revision 2,

'Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b,'

(EPID L-2020-LLA-0018)," dated October 1, 2020.

U.S. Nuclear Regulatory Commission March 31, 2021 Page 2

5. Letter from B. Vaidya (Project Manager, U.S Nuclear Regulatory Commission) to D. Rhoades (Exelon Generation Company, LLC), "Second Round - Request for Additional Information (RAIs) for LaSalle License Amendment Request to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b,' (EPID L-2020-LLA-0018)" dated March 1, 2021.

In Reference 1, Exelon Generation Company, LLC (EGC) submitted a request to the U.S.

Nuclear Regulatory Commission (NRC) for a revision to the Technical Specifications (TS)

(Appendix A) of Renewed Facility Operating License Nos. NPF-11 and NPF-18 for LaSalle County Station, Units 1 and 2.

EGCs proposed license amendment request (LAR) would revise Technical Specifications (TS) requirements to permit the use of Risk-Informed Completion Times (RICT) for actions to be taken when limiting conditions for operation are not met. The proposed changes are based on Technical Specifications Task Force Traveler (TSTF)-505, Revision 2, "Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b," dated July 2, 2018 (ADAMS Package Accession No. ML18269A041).

On September 3, 2020, the NRC provided a Request for Additional Information (RAI)

(Reference 2) to support their continued review of Reference 1. On September 16, 2020, the NRC amended its September 3, 2020 letter to revise the due dates for its requests for additional information (Reference 3). On October 1, 2020, Reference 4 was submitted in response to Reference 2.

On March 1, 2021, the NRC provided EGC with a second round RAI (Reference 5) to support their continued review of Reference 1. to this letter contains the NRCs request for additional information along with EGCs response to Reference 5. Attachment 2 to this letter contains the relevant steps of LOA-AP-201 procedure along with descriptions of each step. Attachment 3 to this letter contains Table 8.3-1, "Loading on 4160-Volt Buses," of the LaSalle County Station Updated Final Safety Analysis Report.

EGC has reviewed the information supporting a finding of no significant hazards consideration and the environmental consideration provided to the NRC in Reference 1. The supplemental information provided in this letter does not affect the bases for concluding that the proposed license amendment does not involve a significant hazards consideration. Furthermore, the supplemental information provided in this letter does not affect the bases for concluding that neither an environmental impact statement nor an environmental assessment needs to be prepared in connection with the proposed amendment.

U.S. Nuclear Regulatory Commission March 31, 2021 Page 3 There are no regulatory commitments contained in this letter.

Should you have any questions regarding this submittal, please contact Jason Taken at 630-657-3660.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 31st day of March 2021.

Respectfully, Dwi Murray Sr. Manager - Licensing Exelon Generation Company, LLC Attachments:

1. Response to Request for Additional Information

2. LOA-AP-201 Actions with Descriptions

3. Load List and Equipment Response During a LOCA cc: NRC Regional Administrator, Region III NRC Senior Resident Inspector - LaSalle County Station NRC Project Manager, NRR - LaSalle County Station Illinois Emergency Management Agency - Division of Nuclear Safety

ATTACHMENT 1 LaSalle County Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-11 and NPF-18 NRC Docket Nos. 50-373 and 50-374 Response to Request for Additional Information

ATTACHMENT 1 Response to Request for Additional Information RAI-R2 EEEB 1: By letter dated October 1, 2020, Exelons response to EEOB TSTF-505 RAI No. 1, "Technical Specifications Associated with TS 3.8 'Electrical Power Systems impact on Non-accident Unit'," indicates the use of site procedure LOA-AP-101, "Unit 1, AC Power System Abnormal". For the same scenario specified in the September 3, 2020, staff RAI, please provide the following:

Details of any additional defense-in-depth capabilities at LaSalle, in line with stated criteria above, that would allow for a controlled, safe shutdown of the non-accident unit. This pertains to the requested changes to TS 3.8.1.B, TS 3.8.1.C, and TS 3.8.1.E for the Division 2 DGs.

EGC RESPONSE:

The NRC previously approved a time extension for EDG Allowed Outage Time (AOT) from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days, as noted in its Safety Evaluation dated January 30, 2002 (ML012780141). The NRCs Safety Evaluation provides, in pertinent part:

Due to the redundancy of each unit's respective ESF divisions and EDGs, the loss of any one of the EDGs, (i.e., the respective unit's associated Division 1, 2, and 3 EDGs or the opposite unit Division 2 EDG) will not prevent the safe shutdown of the respective unit. The total standby power system, including EDGs and electrical power distribution equipment, satisfies the single failure criterion.

LaSalle County Station is able to withstand and recover from a station blackout (SBO) event of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months in accordance with 10 CFR 50.63, "Loss of all alternating current power." For each unit, an SBO occurs as a result of a loss of offsite power in conjunction with a loss of onsite AC power from the respective unit's Division 1 and 2 EDGs, and failure of the cross-tie breaker to the other unit. The Division 3 EDGs are assumed to be available to support the operation of the high-pressure core spray (HPCS) system during an SBO, but are not classified as "Alternate AC" power sources, because Division 3 EDGs do not supply power to safe shutdown loads. Therefore, even though the Division 3 EDGs are available, the LaSalle County Station coping analysis uses the AC independent approach. The proposed changes do not affect the LaSalle County Station SBO analysis. (emphasis added)

Exelon Generation Company, LLC (EGC) confirms that the NRCs statements above, specifically that the loss of any one of the Emergency Diesel Generators (EDGs) will not prevent the safe shutdown of the respective unit, are reflective of the current licensing basis, and remain true and provide context to the responses provided herein.

Consistent with TSTF-505, Revision 2 and EGCs application to adopt TSTF-505, Revision 2 into the LaSalle County Station (LSCS) licensing basis, there are no conditions presented in EGCs application that represent a loss of function. In considering the adoption of the risk-informed approach to completion times, and applying it to the limiting condition for operation (LCO) identified in this question, EGC identified that in many cases, the backstop completion times are conservative compared to what the probabilistic risk assessment (PRA) model would normally allow. This additional margin demonstrates that sufficient redundancy and diversity exist to mitigate common cause events, and that the configuration presented in each Technical Specifications (TS) Condition are not risk significant.

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ATTACHMENT 1 Response to Request for Additional Information For illustrative purposes of describing how LSCS would respond to the postulated scenario, LSCS, Unit 1, is assumed to be the "accident unit" and LSCS, Unit 2, is the "non-accident unit" with its Division 2 Emergency Diesel Generator (EDG) out of service in a Risk-Informed Completion Time (RICT). The actions and conclusions discussed below would be equivalent if the "accident unit' and "non-accident unit" were reversed, with the assumed EDG in a RICT being on the "non-accident unit." Procedure LOA-AP-101, "Unit 1, AC Power System Abnormal," is specific to the actions for Unit 1 during an abnormal power event. Procedure LOA-AP-201, "Unit 2, AC Power System Abnormal,"

is the identical procedure for Unit 2, and will be referenced when describing actions taken on Unit 2.

Consistent with the TS Bases, Sections 3.8.1 D.1 and D.2, with two of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a design basis accident (DBA) or transient.

In fact, a simultaneous loss of offsite AC sources, a loss of coolant accident (LOCA), and a worst-case single failure were postulated as a part of the design basis in the safety analysis.

As described in TS Bases Section 3.8.1, the OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining the onsite or offsite AC sources OPERABLE during accident conditions in the event of:

1) An assumed loss of all offsite power or all onsite AC power; and

2) A worst case single failure.

The postulated scenario is recognized as a DBA, and is discussed in detail in LSCS Updated Final Safety Analysis Report (UFSAR) Chapter 15, Section 6.5, which discusses the LOCA analysis, and UFSAR Chapter 15, Section 9, which discusses Station Blackout (SBO).

Detailed Overview of Operator Actions and Their Impact to this letter contains the applicable portions of LOA-AP-201 for Unit 2 along with annotations providing further guidance on what is performed in the respective steps. Attachment 3 encompasses Table 8.3-1 of the LSCS UFSAR and contains a load list, associated equipment requirements, start times, and loading requirements, to add granularity on loads powered by AC Buses at LSCS and equipment responses and availability following a LOCA.

Figure 1 represents the initial electric plant line-up following a DLOOP (Dual Unit Loss of Off-Site Power) with a LOCA on Unit 1 and the Unit 2 'A' EDG out of service.

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ATTACHMENT 1 Response to Request for Additional Information Figure 1 - Initial electric plant line-up following a DLOOP with a LOCA on Unit 1 and Unit 2 'A' EDG out of service The postulated scenario results in a Station Blackout (SBO) on Unit 2. LSCS SBO coping method uses Reactor Core Isolation Cooling (RCIC) or High Pressure Core Spray (HPCS) to provide makeup water for core cooling. The HPCS system normally takes suction from the suppression pool, and RCIC suction automatically transfers to the Page 3 of 18

ATTACHMENT 1 Response to Request for Additional Information suppression pool on low condensate storage tank level. Decay heat is removed by discharge of steam through the Safety/Relief Valves into the suppression pool, where the steam is condensed. As a result, gradual heat up of the suppression pool is expected. Per analysis, the suppression pool water inventory is sufficient to make up for decay heat removal requirements and expected leakage during a four-hour station blackout. The suppression pool temperature will remain below the heat capacity temperature limits while providing this water, if cooldown is limited to 20°F/hr.

LSCS, Unit 1 (the accident unit) operators will enter Emergency Operating Procedures (EOP) based on High Drywell Pressure and Low Reactor Water level. LSCS, Unit 2 (the non-accident unit with its Division 2 EDG out of service) operators will enter Emergency Operating Procedures (EOP) based on Low Reactor Water level.

LSCS, Unit 2 will enter LOA-AP-201 due to loss of AC power to Division 1 (241Y) and Division 2 (242Y) 4.16k-volt Safety Related Busses. The procedure starts at step B.1, "Decision Tree."

LOA-AP-201 Step B.1, Decision Tree, directs operators to perform Attachment K, "Station Blackout Contingencies," B.2, "Loss of Bus 241Y," and B.3, "Loss of Bus 242Y."

Note: Either Unit 2 Division 1 AC bus (241Y) or Division 2 AC bus (242Y) may be recovered first. For this postulated scenario, Unit 2 Division 1 AC bus (241Y) has been chosen to be recovered first (LOA-AP-201, B.2, "Loss of Bus 241Y").

LOA-AP-201, Step B.2, "Loss of Bus 241Y," restores AC power to the Unit 2 Division 1 AC bus from the Division 1 EDG (the common EDG, 0 DG) using the Division 1 Unit tie breakers (ACB 1414 and ACB 2414). To accomplish this, Division 1 Unit tie breakers (ACB 1414 and ACB 2414) interlocks will be defeated per LOA-AP-201, Attachment C.

Figure 2 represents the final Division 1 AC electrical lineup.

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ATTACHMENT 1 Response to Request for Additional Information Figure 2 - AC power restored to Unit 2 Division 1 AC Bus from Division 1 EDG (0 DG)

Concurrently, operators will perform LOA-AP-201, Attachment K, "Station Blackout Contingencies." Actions in LOA-AP-201, Attachment K, include load shedding of non-essential DC loads, establishing reactor pressure control with Safety Relief Valves (SRVs) from the Auxiliary Electric Equipment Room (AEER) and opening panel doors in the Main Control Room (MCR) and AEER. Attachment 2, Table 1, of this letter provides a timeline of Unit 2 response and key operator actions during the 4-hour SBO coping time.

Following restoration of Unit 2 Division 1 AC power (LOA-AP-201, Step B.2.15), 2A Residual Heat Removal (RHR) will be placed in the Suppression Pool cooling mode (containment cooling) within 15 minutes per LOA-AP-201, Attachment K, LGA-003, "Primary Containment Control," and LGA-RH-203, "Unit 2 A/B RHR Operations in the LGAS/LSAMGS."

Once Suppression Pool cooling is placed into operation, reactor depressurization may continue at a rate not to exceed 100°F/hr.

LOA-AP-201, B.3, "Loss of Bus 242Y," will be performed next to restore AC power to the Unit 2 Division 2 AC bus (242Y) from the Unit 1 Division 2 EDG (1A DG) using the Division 2 Unit tie breakers (ACB 1424 and ACB 2424). To accomplish this, Division 2 Unit tie breakers (ACB 1424 and ACB 2424) interlocks will be defeated per LOA-AP-201, Page 5 of 18

ATTACHMENT 1 Response to Request for Additional Information Attachment G. LOA-AP-201, Attachment G, Step 6.10, is the step that will energize the Unit 2 Division 2 AC bus.

Figure 3 represents the final Division 2 AC electrical lineup.

Figure 3 - AC power restored to Unit 2 Division 2 AC Bus from Unit 1 Division 2 EDG (1A DG).

At this point in the electrical plant system restoration, Unit 2, the non-accident unit, has AC power to Division 1 and Division 2 AC buses required to support safe shutdown.

Consistent with the LSCS design basis and current Technical Specifications, only one division of AC power on Unit 2, the non-accident unit, would be required to permit safe shutdown.

Operator Staffing Technical Specifications (TS) 5.0, "Administrative Controls," Section 5.1.2, TS Section 5.2.2, "Unit Staff," and OP-LA-101-111-1001, "On-Shift Staffing Requirements," provide the minimum shift staffing requirements with both Unit 1 and Unit 2 in Modes 1, 2 or 3.

The minimum shift requirements are (1) Shift Manager, (1) Unit Supervisor, (1) Shift Technical Advisor (STA), (3) Reactor Operators, (3) Non-Licensed Operators, (1) Fire Brigade Leader and (4) Fire Brigade Members. Operator Staffing is sufficient to respond Page 6 of 18

ATTACHMENT 1 Response to Request for Additional Information to a LOCA on one unit with a corresponding loss of off-site power on both Units with any one Emergency Diesel Generator (EDG) in RICT.

Administrative Controls Supporting Defense-In-Depth EGC applies rigor in protecting operable equipment when a system is taken out of service for maintenance. For example, if LSCS were to be in Condition TS 3.8.1.A, One required offsite circuit inoperable, and a RICT was used, compensatory measures and risk management actions (RMAs), not credited in the RICT calculation, would be implemented. The RMAs support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs. Such RMAs are intended to maintain the risk below acceptable regulatory risk thresholds, and account for any uncertainties associated with the calculated RICT. The actions for TS 3.8.1.A are described in Enclosure 12 of Reference 1 and include:

Actions to increase risk awareness and control such as: briefing of the on-shift operations crew concerning the unit activities, including any compensatory measures established, and review of the appropriate EOPs for a Loss of Offsite Power and station blackout including bus crossties; notification of the TSO of the configuration so that any planned activities with the potential to cause a grid disturbance are deferred; and, proactive implementation of RMAs during times of high grid stress conditions prior to reaching the RMAT, such as during high demand conditions.

Actions to reduce the duration of maintenance activities such as: creation of a sub-schedule related to the specific evolution (if preplanned) which is reviewed for personnel resource availability; confirmation of parts availability prior to entry into a preplanned RICT; and, walkdown of work prior to execution.

Actions to minimize the magnitude of the risk increase, such as: evaluation of weather conditions for threats to the reliability of remaining offsite power supplies; deferral of elective maintenance in the switchyard, on the station electrical distribution systems, and on the main and auxiliary transformers associated with the unit; protection of the remaining offsite source, including switchyard and transformer, and deferral of planned maintenance or testing that affects the reliability of DGs and their associated support equipment (i.e. treat these as protected equipment); and, implementation of 10 CFR 50.65(a)(4) fire-specific RMAs associated with the affected offsite source.

If severe weather or conditions are expected, then planned unavailability of AC power sources would be deferred. If an offsite power source becomes unavailable or degraded, or the risk of losing offsite power significantly increases due to severe weather, then systems required to mitigate the loss of offsite power would be made available as soon as possible.

In addition to the above-described RMAs, the RMAs for TS Conditions 3.8.1.B and 3.8.1.E are provided in Enclosure 12 of Reference 1.

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ATTACHMENT 1 Response to Request for Additional Information EGC Processes Used To Implement Risk Management Actions During Equipment Unavailability OP-AA-108-117, "Protected Equipment Program," provides guidance for protecting equipment to minimize plant risk. This involves limiting or prohibiting operation or maintenance of plant equipment when SSCs are made unavailable.

The intent of protecting systems and components is to provide additional administrative barriers to guard against inadvertently rendering a component or system, which is important to unit risk and nuclear safety, inoperable or unavailable. It is also applicable to those systems and activities that pose a potential risk to generation.

Protected equipment actions taken in accordance with this procedure support the Configuration Risk Management Program and are classified as risk management actions for the purpose of compliance with 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," subsection (a)(4).

This procedure applies to online and shutdown conditions.

The online goal is to maintain plant risk within acceptable levels by maintaining defense in depth of key safety functions, preventing inadvertent plant trips, transients, or Technical Specification Limiting Conditions for Operations (LCO) entries.

The shutdown goal is to maintain shutdown risk within acceptable levels by maintaining defense in depth of key safety functions.

Key Safety Functions:

Decay Heat Removal Spent Fuel Pool Cooling Inventory Control Electrical Power (includes both onsite & offsite power)

Reactivity Control Primary Containment Integrity (Containment Isolation, Containment Pressure and Temperature Control)

WC-AA-101, "On-Line Work Control Process," establishes the administrative controls for performing on-line maintenance of structures/systems/components (SSC) to enhance overall plant safety and reliability. This procedure applies to units in power operations in Modes 1, 2.

Corrective, preventive, and predictive maintenance activities are performed on SSCs important to safety and reliability at power to ensure that an SSCs overall reliability will be maintained or improved. Maintenance activities are planned and executed within established bounds and acceptable levels of risk maintain overall plant safety. A configuration risk assessment of planned maintenance activities is conducted prior to initiating any maintenance activity.

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ATTACHMENT 1 Response to Request for Additional Information On-Line Work Control is based upon a 13-week cycle template containing work windows on major safety related and Risk Significant SSCs.

The Operating Shift continuously evaluates the risk of the scheduled on-line maintenance activity based upon conditions, such as the power grid stability, the weather forecast, and the current plant and SSC status. This includes information obtained from day ahead forecasts. If severe weather or conditions that are potential HREs for loss of offsite power are expected, then planned unavailability of AC power sources shall be deferred.

For example, if an offsite power source becomes unavailable or degraded, or the risk of losing offsite power significantly increases due to severe weather, systems required to mitigate the loss of offsite power shall be made available as soon as possible.

OU-AA-103, "Shutdown Safety Management Program," (SSMP) uses as its basis the philosophy and recommendations stated in NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management," and INPO 06-008, "Guidelines for Conduct of Outages at Nuclear Power Plants." The SSMP is also designed to meet the applicable requirements of 10 CFR 50.65(a)(4) and NUMARC 93-01, "Industry Guidance for monitoring the Effectiveness of Maintenance at Nuclear Power Plants."

Risk Mitigation Practices with Time Critical Actions OP-LA-102-106, "LaSalle Station Operator Response Time Program," provides response times for conditions that may be experienced during transients at LSCS.

Noteworthy time critical actions relevant to the question are provided below.

Several time-critical risk-significant operator actions are well-practiced, and time validated in accordance with OP-LA-102-106. Relevant examples include:

TCA16: Manual start of RHR Containment Cooling Mode, RHR in pool cooling.

The SBO analyses for suppression pool temperature assume that suppression pool cooling is established <=15 minutes following a SBO.

o Last validated on June 15, 2018.

TCA22: Control of the ADS valves from the AEER can be established within 20 minutes of initiation of SBO.

o Last validated September 6, 2019.

TCA24: All loads are shed within 30 minutes after SBO begins, with the exception of the 250-Vdc MCC 121X and MCC 221X loads, which are shed within 180 minutes after SBO begins.

o Last validated September 6, 2019.

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ATTACHMENT 1 Response to Request for Additional Information Please also identify any capabilities assumed initially unavailable but eventually recovered including their recovery times and relevant impact.

EGC RESPONSE:

As described in the response to the first question of RAI-R2 EEEB 1, a loss of all AC power occurs on the non-accident (Unit 2), initially rendering all Division 1 and 2 AC powered loads on the non-accident unit unavailable. AC power is re-aligned and containment cooling established as described in the response, and the associated completion time actions are provided in Table 1 of Attachment 2.

Clarification on when procedure LOA-AP-101(201) would be implemented (i.e. (1) prior to entry into the TS LCO or (2) during a postulated design basis accident condition).

EGC RESPONSE:

The purpose of LOA-AP-101(201), "Unit 1(2), AC Power System Abnormal," is to respond to a transient on the LSCS electrical power system.

LOA-AP-101(201) is designed to provide flexibility to operators to restore the electrical plant system from a transient based on conditions present at the time of the transient.

The symptoms or entry conditions that may necessitate executing the procedure are as follows:

- Loss of 345KV grid.

- Loss of Ring Bus.

- Loss of SAT 142 and/or UAT 141.

- Failure of DGs 0, 1A, and/or 1B to start when required.

- Loss of various 4KV & 480 VAC ESS and Non-ESS buses.

- 4kV ESS Bus Degraded Voltage.

- Failure of Voltage Regulating Transformer.

- Loss of single phase or degraded single phase.

These entry conditions intend to capture the diversity of events that may require AC power restoration, but there may be conditions not expressly covered by the list above which would also require entry into this procedure. This procedure is not used under normal operating conditions absent an electrical power system transient, and therefore, this abnormal procedure would not be entered prior to entry into a TS Condition Statement without a corresponding transient. During planned TS Completion Time, equipment is taken out of service consistent with normal operating procedures.

In summary, based on the information provided in the above response for RAI-R2-EEEB 1, which is supported by the current licensing basis, the inoperability of any one of the EDGs, concurrent with the postulated scenario (DBA LOCA with a complete loss of off-site power) will not prevent safe shutdown of the unit with its Division 1 or Division 2 EDG out of service. Whether the EDG is in a RICT, or in the already-approved Allowed Outage Times for EDGs being inoperable, this conclusion remains unchanged.

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ATTACHMENT 1 Response to Request for Additional Information RAI-R2 EEEB 2: For the conditions postulated in Table E1-1, please clarify if procedure LOA-AP-101, "Unit 1, AC Power System Abnormal," would be implemented for the safe shutdown of the non-accident unit under the same conditions specified in RAI EEEB 1 above, including the requested information for defense-in-depth capabilities, when the indicated Division 2 SSC is in a RICT for the following TSs:

TS 3.3.8.1.A - One or more loss of power (LOP) instrument channels EGC RESPONSE:

With one or more channels of a Function inoperable, the Function may not be capable of performing the intended function. Therefore, only 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in a DG initiation), Condition B must be entered and its Required Action taken.

For the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A)

OOS) the Unit 2 Division 2 EDG (2A) is assumed to be out of service (OOS). Each Division 1, 2, and 3 Emergency Busses has its own independent loss of power instrumentation and associated trip logic. For example, a loss of 2A EDG will not affect the Division 1 loss of power instrumentation or its trip logic.

In the event the Unit 2 Division 2 Loss of Power (LOP) Instrumentation is inoperable at the time of the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A) OOS) were to occur, the response would be similar to that described in RAI-R2-EEEB 1 response.

LOA-AP-201 would be entered to restore Unit 2 Division 1 AC bus (241Y) from the Division 1 EDG (0 DG) and LOA-AP-201, Attachment K, "Station Blackout Contingencies," would be implemented.

LOA-AP-201 would be entered to restore Unit 2 Division 2 AC bus (242Y) from the Unit 1 Division 2 EDG (1A DG). With Unit 2 Division 2 Loss of Power (LOP) Instrumentation inoperable and not placed in the trip condition, this condition does not prevent restoring Unit 2 Division 2 AC bus (242Y) from the Unit 1 Division 2 EDG (1A DG).

Additionally, consistent with the EGC Work Management process and measures described in RAI-R2-EEEB 1 response, with the Unit 2 Division 2 EDG (2A) OOS, no activities would be scheduled or performed on Unit 1 Division 2, Unit 2 Division 1 or Unit 2 Division 3 Loss of Power Instrumentation. For planned activities, TS 3.3.8.1 Required Action A.1 would not be entered concurrently for Division 1, 2 or 3 Loss of Power Instrumentation.

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ATTACHMENT 1 Response to Request for Additional Information Furthermore, consistent with NEI 06-09, "Risk-Informed Technical Specifications Initiative 4b Risk-Managed Technical Specifications (RMTS) Guidelines," RMTS cannot be voluntarily entered if:

1) the configuration-specific risk exceeds the instantaneous limits of 10-3/year CDF or 10-4/year LERF;

2) the ICDP or ILERP limit has been reached prior to exceeding the frontstop CT; or

3) a total loss of specified safety function for the affected TS system occurs.

If an emergent failure, or degraded or non-conforming condition is discovered for a redundant SSC that results in a total loss of TS specified safety function while the RMTS are in effect, then the RICT is exited and the associated applicable TS Required Actions are considered not met, and subsequent TS required actions are required to be implemented.

Additionally, LSCS procedure LOA-DG-201, "DG Failure," provides the operator direction to start and load any EDGs that does not start on bus undervoltage when required.

TS 3.8.4.A - 125 VDC battery charger EGC RESPONSE:

To aid in understanding equipment line-ups, and power sources, Figure 4 is provided for the 125 VDC power subsystems.

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ATTACHMENT 1 Response to Request for Additional Information Figure 4 - 125 VDC Subsystem Drawing Both Units at LSCS are designed with (2) fully qualified battery chargers for the 125 VDC Division 1 and Division 2 electrical power subsystems. Only 1 battery charger per division is online at any given time except when swapping battery chargers from primary to backup. Maintenance is performed periodically on the alternate (offline) battery charger. Scheduled maintenance is not performed on both the alternate and required battery chargers at the same time.

Entry into TS LCO 3.8.4 would result from an emergent failure of the online (required) battery charger.

In the event of a failure of the online (required) battery charger, the alternate (offline) battery charger would be placed online per LOA-DC-101(201), "Unit 1(2) DC Power System Failure," Section B.1, "Loss of a Battery Charger."

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ATTACHMENT 1 Response to Request for Additional Information If the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A)

OOS) were to occur with no operating Unit 2 Division 2 battery charger providing DC power, the response would be similar to that described in RAI-R2-EEEB 1 response.

LOA-AP-201 would be entered to restore Unit 2 Division 1 AC bus (241Y) from the Division 1 EDG (0 DG) and LOA-AP-201, Attachment K, "Station Blackout Contingencies," would be implemented.

Once Unit 2 Division 2 AC bus is energized from the Unit 1 Division 2 EDG (1A DG), the alternate (offline) Unit 2 Division 2 DC battery charger would be placed online.

No loss of safety functions occurs.

TS 3.8.4.B & E - 125 VDC electrical power subsystem EGC RESPONSE:

TS 3.8.4 Condition B:

This condition represents one division with a loss of ability to completely respond to an event, and a potential loss of ability to remain energized during normal operation.

In the event the Unit 2 Division 2 125 VDC electrical power subsystem is inoperable at the time of the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A) OOS) were to occur, the response would be similar to that described in RAI-R2-EEEB 1 response.

LOA-AP-201 would be entered to restore Unit 2 Division 1 AC bus (241Y) from the Division 1 EDG (0 DG) and LOA-AP-201, Attachment K, "Station Blackout Contingencies," would be implemented.

However, in this case, the Unit 2 Division 2 125 VDC electrical power subsystem would have to be restored to a functional state to allow restoring the Unit 2 Division 2 AC bus (242Y) from the Unit 1 Division 2 EDG (1A DG).

No loss of safety functions occurs.

TS 3.8.4 Condition E:

In the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A)

OOS), Unit 1 Division 2 125 VDC electrical power subsystem remains energized from the Unit 1 Division 2 EDG (1A) and provides power to the Unit 1 Division 2 Battery Charger ensuring redundant Division 2 features (e.g., a standby gas treatment subsystem, Control Room Area Filtration (CRAF) subsystem, Control Room Area Ventilation Air Conditioning (AC) System) will function in the event of a design basis event.

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ATTACHMENT 1 Response to Request for Additional Information LOA-AP-201 would be entered to restore Unit 2 Division 1 AC bus (241Y) from the Division 1 EDG (0 DG) and LOA-AP-201, Attachment K, "Station Blackout Contingencies," would be implemented.

However, in this case, the Unit 2 Division 2 125 VDC electrical power subsystem would have to be restored to a functional state to allow restoring the Unit 2 Division 2 AC bus (242Y) from the Unit 1 Division 2 EDG (1A DG).

LOA-AP-201 would be entered regarding any loss of AC power that occurred as a result of the postulated scenario and sequence to restore equipment would be as discussed previously in RAI-R2-EEEB 1 response.

No loss of safety functions occurs.

TS 3.8.7.A - AC Electrical power distribution subsystem EGC RESPONSE:

With one or more Division 1 and 2 required AC buses, load centers, motor control centers, or distribution panels inoperable and a loss of function has not yet occurred, the remaining AC electrical power distribution subsystems 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.

In the event the Unit 2 Division 2 AC Electrical power distribution subsystem is inoperable at the time of the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A) OOS) were to occur, the response would be similar to that described in RAI-R2-EEEB 1 response.

LOA-AP-201 would be entered to restore Unit 2 Division 1 AC bus (241Y) from the Division 1 EDG (0 DG) and LOA-AP-201, Attachment K, "Station Blackout Contingencies," would be implemented.

However, in this case, the Unit 2 Division 2 AC Electrical power distribution subsystem would have to be restored to a functional state to allow restoring the Unit 2 Division 2 AC bus (242Y) from the Unit 1 Division 2 EDG (1A DG) or restoring redundant Division 2 equipment (e.g. Division 2 ECCS or Suppression Pool subsystems).

For the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A)

OOS), the Unit 2 Division 2 EDG (2A) is assumed to be OOS. Consistent with the EGC Work Management process, with the Unit 2 Division 2 EDG (2A) OOS, no activities would be scheduled or performed on Unit 2 Division 1, Unit 1 Division 2, or Unit 2 Division 3 AC Electrical power distribution subsystems. For planned activities, TS 3.8.7 Required Action A.1 would only be entered for either Division 1 or 2 AC electrical power distribution subsystems, and not both.

Furthermore, consistent with NEI 06-09, "Risk-Informed Technical Specifications Initiative 4b Risk-Managed Technical Specifications (RMTS) Guidelines," RMTS cannot be voluntarily entered if:

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ATTACHMENT 1 Response to Request for Additional Information

1) the configuration-specific risk exceeds the instantaneous limits of 10-3/year CDF or 10-4/year LERF;

2) the ICDP or ILERP limit has been reached prior to exceeding the frontstop CT; or

3) a total loss of specified safety function for the affected TS system occurs.

If an emergent failure, or degraded or non-conforming condition is discovered for a redundant SSC that results in a total loss of TS specified safety function while the RMTS are in effect, then the RICT is exited and the associated applicable TS Required Actions are considered not met, and subsequent TS required actions are required to be implemented.

No loss of safety functions occurs.

TS 3.8.7.B - DC electrical power distribution subsystem EGC RESPONSE:

With one or more Division 1 and 2 DC electrical distribution subsystems inoperable and a loss of function has not yet occurred, the remaining DC electrical power distribution subsystems 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.

In the event the Unit 2 Division 2 DC Electrical power distribution subsystem was inoperable at the time of the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A) OOS) were to occur, the response would be similar to that described in RAI-R2-EEEB 1 response.

LOA-AP-201 would be entered to restore Unit 2 Division 1 AC bus (241Y) from the Division 1 EDG (0 DG) and LOA-AP-201, Attachment K, "Station Blackout Contingencies," would be implemented.

However, in this case, the Unit 2 Division 2 DC Electrical power distribution subsystem may have to be restored to a functional state to allow restoring the Unit 2 Division 2 AC bus (242Y) from the Unit 1 Division 2 EDG (1A DG) and restoring redundant Division 2 equipment (e.g. Division 2 ECCS or Suppression Pool subsystems).

Furthermore, consistent with NEI 06-09, "Risk-Informed Technical Specifications Initiative 4b Risk-Managed Technical Specifications (RMTS) Guidelines," RMTS cannot be voluntarily entered if:

1) the configuration-specific risk exceeds the instantaneous limits of 10-3/year CDF or 10-4/year LERF;

2) the ICDP or ILERP limit has been reached prior to exceeding the frontstop CT; or

3) a total loss of specified safety function for the affected TS system occurs.

If an emergent failure, or degraded or non-conforming condition is discovered for a redundant SSC that results in a total loss of TS specified safety function while the RMTS Page 16 of 18

ATTACHMENT 1 Response to Request for Additional Information are in effect, then the RICT is exited and the associated applicable TS Required Actions are considered not met, and subsequent TS required actions are required to be implemented.

For the postulated scenario, the Unit 2 Division 2 EDG (2A) is assumed to be OOS.

Consistent with the EGC Work Management process with the Unit 2 Division 2 EDG (2A)

OOS, no activities would be scheduled or performed on Unit 1 Division 2, Unit 2 Division 1, or Unit 2 Division 3 DC electrical distribution subsystems. For planned activities in this configuration, TS 3.8.7 RA B.1 would only be entered for the Unit 2 Division 2 DC electrical power distribution subsystem.

No loss of safety functions occurs.

TS 3.8.7.D - Opposite unit Division 2 AC or DC electrical power distribution subsystem EGC RESPONSE:

In the postulated scenario (Unit 1 LOCA and DLOOP with Unit 2 Division 2 EDG (2A)

OOS), the Unit 1 Division 2 AC and DC electrical power subsystems remains energized from the Unit 1 Division 2 EDG (1A). Unit 1 Division 2 AC and DC electrical power subsystems provide power to ensure redundant Unit 1 Division 2 features (e.g., a standby gas treatment subsystem, Control Room Area Filtration (CRAF) subsystem, Control Room Area Ventilation Air Conditioning (AC) System) will function in the event of a design basis event.