Text

Units 1 and 2 - Response to Requests for Additional Information (Rals) Regarding License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk Informed .
	ML23011A280
Person / Time
Site:	Point Beach
Issue date:	01/11/2023
From:	Strand D; Point Beach
To:	; Office of Nuclear Reactor Regulation, Document Control Desk
References
	L-2023-003
	Download: ML23011A280 (1)
	v • d • e

NEXTera L-2023-003 ENERGY e 10 CFR 50.90

~ BEACH January 11 , 2023 U. S. Nuclear Regulatory Commission Attn : Document Control Desk Washington D C 20555-0001 RE: Point Beach Nuclear Plant, Units 1 and 2 Docket Nos. 50-266 and 50-301 Renewed Facility Operating Licenses DPR-24 and DPR-27 Response to Requests for Additional Information (RAls) Regarding License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505 ,

Revision 2, "Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b"

References:

1. License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk Informed Extended Completion Times -

RITSTF Initiative 4b", dated May 20, 2022 (ADAMS Accession No. ML22192A152)

2. Technical Specification Task Force (TSTF) letter to the NRC, "TSTF Comments on Draft Safety Evaluation for Traveler TSTF-505, 'Provide Risk-Informed Extended Completion Times' and Submittal of TSTF-505, Revision 2", Revision 2, dated July 2, 2018 (ADAMS Accession No. ML18183A493)

3. NRC Safety Evaluation , "Final Revised Model Safety Evaluation of Traveler TSTF-505, Revision 2, 'Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b"', dated November 21, 2018 (ADAMS Accession No. ML 182.53A085)

4. NRC electronic memorandum dated December 21 , 2022, Final RAI - Point Beach 1 & 2 - License Amendment Request Regarding TSTF-505 (EPID No. L-2022-LLA-0074)

In Reference 1, NextEra Energy Point Beach , LLC (NextEra) submitted license amendment request (LAR) 273 for Point Beach Nuclear Plant Units 1 and 2 (Point Beach) , respectively . The proposed license amendments would modify the Point Beach Technical Specifications (TS) to permit the use of Risk Informed Completion Times in accordance with TSTF-505, Revision 2, "Provide Risk-Informed Extend Completion Times - RITSTF Initiative 4b (Reference 2) . A model safety evaluation was provided by the NRC to the TSTF on November 21 , 2018 (Reference 3).

In Reference 4, the NRC requested add itional information deemed necessary to complete its review.

The enclosure to this letter provides NextEra's response to the request for additional information (RAI) .

Attachment 1 to the enclosure provides a revised TS Section 5.5.7 markup page resulting from the RAI responses . Attachment 2 provides revised TS Bases markup pages resulting from the RAI responses . The enclosed TS Section 5.5.7 markup page and TS Bases markup pages supersede and replace the corresponding TS Section 5.5.7 markup page and TS Bases markup pages of Reference 1. The proposed TS Bases changes are provided for information only and will be incorporated in accordance with the Point Beach TS Bases Control Program upon implementation of the requested amendments.

The supplements included in this RAI response provide additional information that clarifies the application ,

do not expand the scope of the application as originally noticed, and should not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Page 2 of 2 This letter contains no new regulatory commitments.

Should you have any questions regarding this submission, please contact Mr. Kenneth Mack, Fleet Licensing Manager, at 561-904-3635.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on the _I_l_day of January 2023.

Sincerely, Dianne Strand General Manager, Regulatory Affairs cc: USNRC Regional Administrator, Region Ill Project Manager, USNRC, Point Beach Nuclear Plant Resident Inspector, USNRC, Point Beach Nuclear Plant Public Service Commission of Wisconsin Attachments (3)

1. Proposed Technical Specification Section 5.5.7 (Mark-Up) - revised

2. Proposed Technical Specification Bases Changes (Mark-Up) - revised

3. Revised Table E1-1, List of Revised Required Actions to Corresponding PRA Functions

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 1of19 Response to Request for Additional lnforrriation (RAI)

License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b" Probabj!jstjc Rjsk Assessment Licensjng Branch A lAPLAl Qyestions APLA-RAl-1 (Audit Question 1) - Performance Monitoring Nuclear Energy Institute (NEI) 06-09, Revision 0, "Risk Informed Technical Specifications Initiative 4b: Risk Managed Technical Specifications (RMTS)" (ML063390639) , and the NRC's SE to this guidance (ML071200238), specifies that, in accordance with the fifth key safety principle of Regulatory Guide (RG) 1.174, Revision 3, "An Approach for using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," (ML17317A256), and RG 1.177, Revision 2, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications" (ML20164A034), the impact of the RICT program should be monitored using performance management strategies. Additionally, the final SE for NEI 06-09-A, "Risk Informed Technical Specifications Initiative 4b Risk Managed Technical Specifications (RMTS) Guidelines" (ML12286A322), specifies that the LAR should include a description of the monitoring program. Furthermore, NRC staff position C.3.2, "Scope of the Probabilistic Risk Assessment for Technical Specification Change Evaluations," provided in RG 1.177, Revision 2, for meeting the fifth key safety principle, specifies that performance criteria should be established to assess degradation of operational safety over a period of time. The gu idance in NEI 06-09-A considers the use of Nuclear Management and Resources Council (NUMARC) 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants" (ML18120A069), as endorsed by RG 1.160, Revision 4, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants" (ML18220B281 ), for the implementation of the Maintenance Rule. NU MARC 93-01, Revision 4F, Section 9.0, dated April 2018, contains guidance for the establishment of performance criteria.

a) The LAR does not address how the licensee's RMTS process captures performance monitoring for the SSCs within-scope of the RMTS program. Therefore, -either- Confirm that the Point Beach Maintenance Rule program incorporates the use of performance criteria to evaluate SSC performance as described in NUMARC 93-01, as endorsed by RG 1.160,

-or-b) Describe the approach or method used by Point Beach for SSC performance monitoring, as described in NRC staff position C.3.2 of RG 1.177, Revision 2, for meeting the fifth key safety principle . In the description, include criteria (e.g., qualitative or quantitative), along with the appropriate risk metrics, and explain how the approach and criteria demonstrate the intent to monitor the potential degradation of SSCs in accordance with the NRC final SE for NEI 06-09-A.

NextEra Response:

At Point Beach, NextEra Energy Point Beach, LLC (NextEra) implements the NextEra Nuclear Fleet Maintenance Rule Program which incorporates the use of performance criteria described in NU MARC 93-01 to evaluate structures, systems, and component (SSC) performance. Specifically, NextEra's Fleet administrative procedure, ER-AA-100-2002, Maintenance Rule Program Administration, requires the determination of the risk significance of SSCs within the scope of the Maintenance Rule meet the requirements of NUMARC 93-01. NextEra implements a Maintenance Rule Expert Panel (MREP) consistent with NUMARC 93-01 recommendations.

In addition to NextEra's Maintenance Rule monitoring program, NextEra's Nuclear Fleet administrative procedure, EN-AA-105-1007, Monitoring Requirements for the Risk Informed Completion Time

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 2of19 Program, prescribes requirements for monitoring the impacts of implementing the Risk Informed Completion Time (RICT) Program based on NUMARC 93-01 and will be implemented at Point Beach upon implementation of the approved license amendments.

APLA-RAl-2 (Audit Question 3) - Impact of Seasonal Variations The Tier 3 requ irement of RG 1.177, Revision 2, stipulates that a licensee should develop a program that ensures that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity. Section 2.3.4 of NEI 06-09-A states, in part, that:

If the PRA model is com;tructed using data points or basic events that change as a result of time of year or time of cycle ... , then the RICT calculation shall either 1) use the more conservative assumption at all time, or 2) be adjusted appropriately to reflect the current (e.g ., seasonal or time of cycle) configuration for the feature as modeled in the PRA.

The LAR does not seem to address whether modeling adjustments are needed to account for seasonal and time of cycle dependencies and what kind of adjustments will be made. Therefore, address the following to clarify the treatment of seasonal and time of cycle variations:

a) Explain how the RICT calculations address changes in PRA data points, basic events, and SSC operability constraints as a result of extreme weather conditions, seasonal variations, other environmental factors, or time of cycle. Also, explain how these adjustments are made in the configuration risk management program (CRMP) model and how this approach is consistent with the guidance in NEI 06-09-A and its associated NRC final SE.

b) Describe the criteria used to determine when PRA adjustments due to extreme weather conditions, seasonal variations, other environmental factors, or time of cycle variations need to be made in the CRMP model and what mechanism initiates these changes.

NextEra Response :

a) The PBNP PRA model modifies success criteria based on outside air temperatures for some supporting functions. The primary application defines the number of diesel generator ventilation fans required to maintain temperatures in the diesel generator rooms.

For each of the temperature-based applications, the number of fans or supporting electrical power requirements are adjusted as outside temperatures increase. These changes in success criteria were based on system operations guidelines and system engineer interviews, and modeled as split fractions ,

but can be selected in the RICT CRMP software by choosing the correspond ing alignment based on the current ambient air temperature (see the Data Analysis Notebook, PRA 4.0, Section 3.6 for details).

There are two associated temperature ranges :

Temp <= 80°F and > 80°F.

The PBNP CRMP model has numerous 'Environmentalffest' factors that when implemented, alter the probability accordingly. These factors are documented for the Point Beach 6.04 PRA model of record in Section 5.6 and Table 5.7-1 of the Phoenix OLRM Model Report PBN-BFJR-22-021 . These include (but are not limited to) peak demand, grid work, severe weather (cold, wind/storm), external fires , intake structure fouling , switchyard work, activities that could induce a reactor trip, activities that could induce a loss of feedwater, and activities that may cause an inadvertent safety injection signal. These are applied based on review of work packages/activities, entry into specific Abnormal Operating Procedures, or Grid Operator/Plant defined conditions. Report PBN-BFJR-22-021 will be updated to incorporate the 6.05 PRA model of record into the Point Beach CRMP for use in the RICT program.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 3of19 b) Section 5.6 of the Phoenix OLRM Model Report PBN-BFJR-22-021 describes the process for mapping plant activities and conditions from PBNP's plant scheduling software to specified Environmental/Test Factors. If the plant scheduling software indicates an activity is in place, the appropriate Environmental/ Test Factors are applied in the CRMP model. For other plant activities and conditions not explicitly listed in the plant scheduling software, Environmental/Test Factors can be applied to the CRMP model in the" Plant State" window of the Phoenix Risk Monitor Software.

These factors are applied based on work activity review by Operations or Work Control personnel.

For example, if a test procedure or work order activity contains a caution or warning statement, or a review of the procedure or activity by the Operations Work Control personnel resulted in a similar caution, then the Environmental/Test Factor corresponding to the condition is added to the configuration that is being addressed in the CRMP model.

As stated above in the response to part a), PBN-BFJR-22-021 currently documents the CRMP model using the Point Beach 6.04 model of record. This report will be updated to incorporate the 6.05 model of record for use in the RICT program APLA-RAl-3 (Audit Question 7) - Technical Adequacy of Internal Events and Fire PRA In Enclosure 2 of the LAR, Section 1, the licensee states, "The PBN [Point Beach] internal events, internal flooding, and fire PRA [probabilistic risk assessment] models described within this LAR are based on those described with NextEra Energy PBN submittals regarding adoption of 10 CFR 50.69, "Risk-informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors" (ML17243A201) with routine maintenance and updates applied."

The NRC staffs SE of the LAR to adopt 10 CFR 50.69 dated November 26, 2018 (ML18289A378), Section 3.5.1, for internal events and fire PRAs, stated that the NRC staff found significant errors and weaknesses in the internal events and fire PRAs, but concluded that this would be resolved prior to implementation of the 10 CFR 50.69 categorization process by the licensee's completion of implementation items ii, iii, iv, v, vi, vii, viii, ix, and x. Therefore, the NRC staff found the quality and level of detail of the internal events and fire PRAs would meet the requirement in 10 CFR 50.69(c)(1 )(i) upon completion of these implementation items.

a) Confirm the completion of implementation items ii, iii, iv, v, vi, vii, viii, ix, and x.

b) Justify that the implementation items have an inconsequential impact on the RICT calculations. In the response, address the basis for the assumption.

NextEra Response:

Implementation of items ii, iii, iv, v, vi, vii, viii, ix, and x in the Point Beach PRA models has been completed. Below is a listing of the implementation items and a description of how the change was implemented.

Implementation Item ii states: "The loss of a 4, 160 VAC bus will be added to the PRA model as a special initiator to resolve internal events finding F&O IE-A1-01." The IAT assessed this F&O as being closed per PBN-BFJR-22-015 (PWROG-22001-P "Independent Assessment of Facts & Observations Closure of the Point Beach Probabilistic Risk Assessment).

Implementation Item iii states: "A new failure mode associated with EOG load management will be added to the internal events and fire PRA model to resolve internal events findings AS-B6-01 and SY-A21-01 and finding PRM-B2-01 ." The IAT assessed F&Os AS-B6-01, SY-A21-01, and PRM-B2-01 as closed per PBN-BFJR-22-015.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 4of19 Implementation Item iv states: "The treatment of power recovery after LOOP events and battery modeling in the PRA model will be revised to be more realistic to resolve internal events finding AS-B7-

01. " The IAT assessed F&O AS-B7-01 as closed per PBN-BFJR-22-015.

Implementation Item v states: "F&O HR-01-01 will be closed by the licensee using an NRG-accepted process." The IAT assessed F&O HR-01-01 as closed per PBN-BFJR-22-015.

Implementation Item vi states: "F&O IF-QU-A6-01 will be closed by the licensee using an NRG-accepted process." The IAT assessed F&O IF-QU-A6-01 as closed following a focused-scope peer review per PBN-BFJR-22-015 .

Implementation Item vii states: "The HEPs developed for the fire PRA model will be updated to remove the graphically distinct credit in the cognitive portion of the HEP. The dependency analysis will be updated, and the fire PRA quantified using these updated Human Error Probabilities." This issue was identified in F&O HRA-B2-01. The IAT assessed F&O HRA-B2-01 as closed per PBN-BFJR-22-015.

Implementation Item viii states: "The basic event mapping tables in the fire PRA will be reviewed and compared to the present basic event mapping associated with each equipment or cable. Those items that are no longer needed will be removed and any incorrect mapping will be updated. The Fire PRA model will be quantified using this updated mapping table." This issue was identified in F&O FQ-A1-01.

The IAT assessed this F&O as closed per PBN-BFJR-22-015.

Implementation Item ix states: "Update the internal events and fire PRA models to credit the Westinghouse Generation Ill RCP seals using the guidance from PWROG-14001-P, Revision 1, and the limitations and conditions in the associated NRC's safety evaluation (ML17200A116), as stated in responses to RAI 10. The additional failure contribution of the Westinghouse RCP shutdown seal bypass failure mode will be added to the PRA models ... " Revision 5 of the NFPA 805 Fire Probabilistic Risk Assessment Quantification Notebook (PRA 8.18) documented the inclusion of modeling to incorporate the Westinghouse Generation Ill RCP seals in accordance with PWROG-14001-P.

Appendix K of PRA 8.18 documents the process used to implement the necessary changes into the fire PRA model. Following the incorporation of the shutdown seal modeling in the fire PRA, Revision 5 of the Internal Events Quantification Notebook (PRA 11.0) updated the internal events PRA to incorporate the modeling changes made in the fire PRA to incorporate the shutdown seals. As the internal floods PRA uses the combined internal events and fire fault tree, the RCP shutdown seal modifications are also included in the internal floods PRA (PRA 7.1 ).

Implementation Item x states: "All changes performed to the PRA to address the above implementation items will be independently reviewed to determine if the resolution of those items in the PRA model constitutes a PRA upgrade. If the review identifies a change is a PRA upgrade, a focused-scope peer review will be performed for that change, and any resulting F&Os will be resolved in the PRA to meet Capability Category II."

PBN-BFJR-22-015 (PWROG-22001-P "Independent Assessment of Facts & Observations Closure of the Point Beach Probabilistic Risk Assessment"), Revision 0, documented the IAT assessment of open findings in the Point Beach PRA models. Section 3.1.2 of PBN-BFJR-22-015, Revision 0 states that "all the F&Os from the internal events PRA were judged to be closed with a PRA maintenance activity that did not require a focused scope peer review." This statement applies to all the above implementation items that are associated with F&Os.

APLA-RAl-4 (Audit Question 8) - Surrogate for TS 3.3.1 Conditions D, E, K, L, M, N, 0, P, Q, and U

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 5of19 In Enclosure 1 of the LAR, Table E1-1, the licensee states that instrumentation associated with TS 3.3.1 functions 2.a, 2.b, 5, 6, 7.a, 7.b, 8, 9.a, 9.b, 10.a, 10.b, 11, 12, 13, 14, 15.a, 15.b, 16, 19, and 21 are not modeled in the PRA. Table E1-1 states for these functions, which are related to TS 3.3.1 conditions D, E, K, L, M, N, 0, P, and U, that one of two inoperable reactor trip breakers will be used as a surrogate for these functions and conditions.

Table E1-1 states that instrumentation associated with TS 3.3.1 condition Q, function 18, "Reactor Trip Breakers (RTB)," is not modeled in the PRA. Table E1-1 for this function states "This SSC [structure, system, and component) is used as a surrogate for other TS 3.3.1 RPS [Reactor Protection System]

Instrumentation Conditions." However, the LAR did not provide an adequate description for the NRC staff to conclude that the PRA modeling will be sufficient.

a) Provide additional detail on the surrogate(s) used (internal events PRA and fire PRA) for TS 3.3.1 functions 2.a, 2.b, 5, 6, 7.a, 7.b, 8, 9.a, 9.b, 10.a, 10.b, 11, 12, 13, 14, 15.a, 15.b, 16, 18, 19, and 21 associated with conditions D, E, K, L, M, N, 0, P, Q, and U.

b) Provide justification that the surrogate(s) adequately captures configuration risk, is conservative and bounding. TS 3.3.1 allows separate condition entry for each function. Include in the discussion configuration risk for one function versus multiple functions.

c) Explain the impact on the RICT calculations for one function inoperable versus multiple functions inoperable.

NextEra Response:

a) Table E1-1 in Enclosure 1 requires some clarification:

1. For Condition K, FU7a, the table states that the process logic is not modeled and the same reactor trip breaker surrogate is used as for the other conditions. However, this process logic is modeled in the PRA for the reactor trip function (gates U1-GRT1320/U1-GRT1160 and U2-GRT1320/ U2-GRT1160), and basic events in this logic would be better surrogates (less conservative) for the TS 3.3.1 functions in general. Nevertheless, the same reactor trip breaker surrogates are used for this condition.

2. For Condition Q, the table states that the RTB logic is not modeled but this logic is used as the surrogate for all the conditions of TS 3.3.1 (except Condition B), as mentioned in the comment in the table. This logic is modeled and is selected as the surrogates for the TS 3.3.1 conditions.

The basic events representing reactor trip breakers for Train A and Train B, U1-RP--BKR-CC-52RTA/U 1-RP--BKR-CC-52RTB and U2-RP--BKR-CC-52RTNU2-RP--BKR-CC-52RTB, are selected for the TS 3.3.1 reactor trip conditions, depending on applicable train.

The modeling of surrogates for these functions is the same in the internal events and fire PRA models.

b) For the process logic associated with these conditions, there are generally three or four channels available, with conditions that address one channel out of service, which would contribute to the overall reactor trip function unavailability. This process logic has more redundancy and diversity than the reactor trip breaker failures selected as surrogates. Redundancy is through the additional channels and diversity is through the different process logic functions that can result in a reactor trip for a given plant state (e.g., low pressurizer pressure (FU7a) and low reactor coolant flow (FU9b) conditions may both be met for the same plant accident state). Thus, the use of the reactor trip breaker basic events is conservative but still representative of the trip function on a train-specific basis.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 6of19 c) For any number of condition entries, the implied assumption is that the reactor trip train is degraded and therefore unavailable. This is reasonable for plant states for which only one condition may be applicable to trip the plant. Use of the breakers bounds the assessment for any number of condition entries allowed by TS up to and including the train being out of service. The RICT calculation will be limiting once the first condition is entered and does not need to be revised based on add itional conditions, as long as those additional conditions only impact the same train represented by the surrogate. The RICT calculation will need to be revised based on additional conditions that could impact the other train and therefore take the other train out of service in the PRA given the conservative choice of surrogates described above. This would appear as a functional loss in the PRA. However, this is only an artifact of the PRA, based on bounding assumptions, and will not represent an actual functional loss in the plant, which would be limited by TS.

APLA-RAl-5 (Audit Question 9) - Surrogate for TS 3.3.2.8 In Enclosure 1 of the LAR, Table E1-1, for TS 3.3.2, states for condition B, function 1.a, "The operator actions for failure to manually actuate SI (safety injection] will be used as a surrogate to conservatively bound the risk increase associated with this function as permitted by NEI 06-09." Table E1-1 states for condition B, function 3.a, "The condition of manual SI function inoperable is used as a surrogate for this condition since an SI signal generates a Cl [containment isolation] signal." In addition, Table E1-1 states for these functions, that the PRA success criteria is not modeled .

a) Provide add itional detail on the surrogate(s) used (internal events PRA, and fire PRA) for TS 3.3.2 condition B, functions 1.a and 3.a.

b) Provide justification that the surrogate(s) adequately captures configu ration risk, is conservative and bounding (internal events PRA, and fire PRA) . TS 3.3.2 allows separate condition entry for each function . Include in the discussion configuration risk for one function versus multiple functions.

c) Explain the impact on the RICT calculations.

NextEra Response:

a) Table E1-1 in Enclosure 1 requires some clarification : The table identifies several SI functions as not modeled in the PRA; however, there is logic associated with safety injection , including the operator action to initiate SI.

Basic events (human failure events) HEP-Sl--EOP-0-04 and HEP-Sl-EOP-0-04F (the fire-specific version of the operator action for manually actuating SI) are selected as the surrogates for Condition B of TS 3.3 .2 in the internal events PRA and fire PRA, respectively. Th is operator action is credited to initiate SI following failure of automatic actuation and is therefore directly applicable.

b) There is one action that is modeled to fail both SI trains, which degrades all SI functions modeled in the PRA, including containment isolation (automatic actuation is also available) . Therefore, it is conservative to use this action as a surrogate for TS 3.3.2 Condition B, and the impact for one function versus multiple is conservatively equivalent, though the model includes the containment isolation function separate from other SI functions and could therefore allow for reduced conservatism if necessary.

c) For any number of condition entries, the implied assumption is that the manual safety injection function is degraded and therefore unavailable. Use of the single action bounds the assessment for any number of condition entries allowed by TS up to and including the function being out of service. The RICT calculation will be limiting once the first condition is entered and does not need to be revised based on additional conditions, as long as those additional conditions only impact the same train represented by

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 7of19 the surrogate. The RICT calculation will need to be revised based on additional conditions that could impact the other train and therefore take the other train out of service in the PRA given the conservative choice of surrogates described above. This would appear as a functional loss in the PRA. However, this is only an artifact of the PRA, based on bounding assumptions, and will not represent an actual functional loss in the plant, which would be limited by TS.

APLA-RAl-6 (Audit Question 10) - Surrogate for TS 3.3.2 Conditions C and D In Enclosure 1 of the LAR, Table E1-1, for TS 3.3.2, states for condition C, function 1.b, "The failure of the automatic SI signals will be used as a surrogate to conservatively bound the risk increase associated with this function as permitted by NEI 06-09." Table E1-1 states for TS 3.3.2, condition C, function 3.b, 'The condition of automatic SI function inoperable is used as a surrogate for this condition since an SI signal generates a Cl signal." Table E1-1 states for TS 3.3 .2, condition D, functions 1.c, 1.d, and 1.e, "The condition of automatic SI function inoperable is used as a surrogate for this condition since it is the same function (SI initiation)." In addition, Table E1-1 states for these functions, that the PRA success criteria is not modeled for these functions.

a) Provide additional details on the surrogate(s) used (internal events PRA, and fire PRA) for TS 3.3.2 conditions C and D, functions 1.b, 3.b, 1.c, 1.d, and 1.e.

b) Provide justification that the surrogate(s) adequately captures configuration risk, is conservative and bounding (internal events PRA, and fire PRA). TS 3.3.2 allows separate condition entry for each function. Include in the discussion configuration risk for one function versus multiple functions.

c) Explain the impact on the RICT calculations for one function inoperable versus multiple functions inoperable.

NextEra Response :

a) Table E1-1 in Enclosure 1 requires some clarification: The table identifies several SI functions as not modeled in the PRA; however, there is logic associated with safety injection , including the operator action to initiate SI.

The gates representing reactor trip breakers for Train A and Train B, U1-GSIA200/ U1-GSIB200 and U2-GSIA200/ U2-GSIB200, are selected for the TS 3.3.2 SI conditions, depending on applicable train .

The modeling of surrogates for these functions is the same in the internal events and fire PRA models.

b) For Condition C, there are two trains, with conditions that address one train out of service, which would contribute to the overall safety injection I isolation function unavailability. In this case, the surrogates are equivalent and therefore adequately represent the conditions. For the process logic associated with Condition D, there are three channels available for each, with conditions that address one channel out of service, which would contribute to the overall safety injection function unavailability. This process logic has more redundancy and diversity than the train-related SI gates selected as surrogates.

Redundancy is through the additional channels and diversity is through the different process logic functions that can result in a safety injection signal for a given plant state (e.g., low pressurizer pressure (FU1d) and low steam line pressure (FU1e) conditions may both be met for the same plant accident state). Thus, the use of the SI gates is conservative but still representative of the safety injection function on a train-specific basis.

c) For any number of condition entries, the implied assumption is that the safety injection I isolation train is degraded and therefore unavailable. This is reasonable for plant states for which only one condition may be applicable to generate a safety injection signal. Use of the SI gates bounds the assessment for

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 8of19 any number of condition entries allowed by TS up to and including the train being out of service. The RICT calculation will be limiting once the first condition is entered and does not need to be revised based on additional conditions, as long as those additional conditions only impact the same train represented by the surrogate. The RICT calculation will need to be revised based on additional conditions that could impact the other train and therefore take the other train out of service in the PRA given the conservative choice of surrogates described above. This would appear as a functional loss in the PRA. However, this is only an artifact of the PRA, based on bounding assumptions, and will not represent an actual functional loss in the plant, which would be limited by TS.

APLA-RAl-7 (Audit Question 11) - Surrogate for TS 3.3.2 Conditions D, F, and G In Enclosure 1 of the LAR, Table E1-1, for TS 3.3.2, states for condition D, function 4.c, "The failure of the model logic for steam generator isolation will be used as a surrogate to conservatively bound the risk increase associated with this function as permitted by NEI 06-09." Table E1-1 states for TS 3.3.2, condition D, functions 4.d, 4.e, 5.b, condition F, function 4.a, and condition G, function 4.b, "The condition of steam generator isolation function inoperable is used as a surrogate for this condition." In addition, table E1-1 states for these functions, that the PRA success criteria is not modeled.

a) Provide additional details on the surrogate(s) used (internal events PRA, and fire PRA) for TS 3.3.2 conditions D, F, and G, functions 4.a, 4.b, 4.c, 4.d , 4.e, and 5.b.

b) Provide justification that the surrogate(s) adequately captures configuration risk, is conservative and bounding (internal events PRA, and fire PRA). TS 3.3.2 allows separate condition entry for each function . Include in the discussion configuration risk for one function versus multiple functions.

c) Explain the impact on the RICT calculations for one function inoperable versus multiple functions inoperable.

NextEra Response:

a) Table E1-1 in Enclosure 1 requires some clarification : The table identifies several steam line and feedwater line isolation signal functions as not modeled in the PRA; however, there is logic associated with these functions; for example, gate U1 -GMS1470.

Gates U 1-GMS1100 and U2-GMS1100 are selected as the surrogates for the steam line and feedwater isolation functions of TS 3.3.2. These gates represent failure to isolate faulted steam generators and include failure of automatic actuation of the isolation function. The modeling of surrogates for these functions is the same in the internal events and fire PRA models.

b) There is one gate (per unit) that is modeled to fail both trains. Therefore, it is conservative to use this gate as a surrogate for TS 3.3.2 Conditions D, F and G, for the isolation functions , and the impact for one function versus multiple is conservatively equivalent, though the model includes train-specific logic to account for steam generator isolation and could therefore allow for reduced conservatism if necessary.

c) For any number of condition entries, the implied assumption is that the steam line and feedwater line isolation functions are degraded and therefore unavailable. Use of the single functional gate bounds the assessment for any number of condition entries allowed by TS up to and including the function(s) being out of service. The RICT calculation will be limiting once the first condition is entered and does not need to be revised based on additional conditions, as long as those additional conditions only impact the same train represented by the surrogate. The RICT calculation will need to be revised based on additional conditions that could impact the other train and therefore take the other train out of service in the PRA given the conservative choice of surrogates described above. This would appear as a

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 9of19 functional loss in the PRA. However, this is only an artifact of the PRA, based on bounding assumptions, and will not represent an actual functional loss in the plant, which would be limited by TS .

APLA-RAl-8 (Audit Question 12) - Surrogate for TS 3.3.2 Conditions D, G, and H In Enclosure 1 of the LAR, Table E1-1, for TS 3.3.2, states for condition D, function 6.b, and condition G, function 6.a, "The failure of the model logic for these relays will be used as a surrogate to conservatively bound the risk increase associated with this function as permitted by NEI 06-09 ." Table E1-1 states for TS 3.3.2, condition H, function 6.d, "The failure of the model logic for starting all four AFW pumps will be used as a surrogate to conservatively bound the risk increase associated with this function as permitted by NEI 06-09." Table E1-1 states for TS 3.3 .2, condition G, function 5.a, "The condition of AFW initiation is used as a surrogate for this condition ." In add ition, table E1 -1 for these functions, states that the PRA success criteria is not modeled .

a) Provide additional details on the surrogate(s) used (internal events PRA, and fire PRA) for TS 3.3.2 conditions D, G, and H, functions 5.a, 6.a, 6.b, and 6.d.

b) Provide justification that the surrogate(s) adequately captures configuration risk, is conservative and bounding (internal events PRA, and fire PRA). TS 3.3.2 allows separate condition entry for each function . Include in the discussion configuration risk for one function versus multiple functions .

c) Explain the impact on the RICT calculations for one function inoperable versus multiple functions inoperable.

NextEra Response :

a) Table E1-1 in Enclosure 1 identifies process logic associated with AFW initiation (and isolation) as not modeled in the PRA; however, this is meant to say that the modeling of the instrument channel is not sufficiently detailed . Therefore, the RICT is conservatively calculated by assuming a bounding failure of other equipment logically associated with these functions ; for example, the surrogates identified below.

For function 6.b, basic events U1-RP--REL-FT-461 BA I U1-RP--REL-FT-461 BB and U2- RP--REL-FT-461 BA I U2-RP--REL-FT-461 BB are identified as surrogates for AFW actuation . These basic events are relay failures that each represent one steam generator Lo-Lo Level channel, for each train . Therefore, these are directly applicable and adequately represent the conditions.

For function 5.a , the choice of surrogate described is not correct. This function is for feedwater isolation and is therefore covered by the conditions/functions covered in AQ- 11 : TS 3.3 .2 Conditions D, F, and G, functions 4.a, 4.b, 4.c, 4.d , 4.e, and 5.b, for which the surrogates are gates U1-GMS1100 and U2-GMS1100, as described in the response to AQ-11.

For function 6.a, the following basic events are identified as surrogates for AFW actuation :

o U1-RP--REL-FT-461 BA, U1-RP--REL-FT-462AA, U1-RP--REL-FT-463CA I o U1 -RP--REL-FT-461BB , U1-RP--REL-FT-462AB, U1-RP--REL-FT-463CB, and o U2-RP--REL-FT-461 BA, U2-RP--REL-FT-462AA, U2-RP--REL-FT-463CA I o U2-RP--REL-FT-461 BB, U2-RP--REL-FT-462AB, U2-RP--REL-FT-463CB These basic events are relay failures that each represent one steam generator Lo-Lo Level channel. Each set of three represents the full train and is selected as the surrogate. Therefore, these sets are directly applicable and adequately represent the cond itions.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 10of19

For function 6.d, gates U1-GAFM3035 and U2-GAFM3035 are selected as the surrogates. These gates represent failure of manual actuation of the MOVs to provide AFW flow and were chosen based on their impact to all AFW. This action is credited to operate the MOVs to provide AFW flow following failure of automatic actuation and is therefore applicable and conservative.

The modeling of the surrogates for the above functions is the same in the internal events and fire PRA models.

b) For function 5.a, see response to AQ-11.

For functions 6.a and 6.b, there are two trains with three channels each, with conditions that address one channel or one train out of service, which would contribute to the overall AFW initiation function unavailability. In this case, the surrogates are functionally equivalent and therefore adequately represent the conditions.

For function 6.d, there is one gate (per unit) that is modeled to fail manual actuation for all AFW, which degrades the AFW functions modeled in the PRA (automatic actuation is also available).

Therefore, it is conservative to use this action as a surrogate for TS 3.3.2 Condition H, and the impact for one function versus multiple is conservatively equivalent or addressed by the other surrogates for those functions .

c) In this case, different functions are represented by different surrogates and therefore can be assessed independently or as a group (e.g., function 6.a versus 6.b). For the conservative cases (e.g., function 6.d), for any number of condition entries, the implied assumption is that the train or function is degraded and therefore unavailable. This is reasonable for plant states for which only one condition may be applicable to generate the signal. Use of the functional gates bounds the assessment for any number of condition entries allowed by TS up to and including the train/function being out of service. In these cases, the RICT calculation will be limiting once the first condition is entered and does not need to be revised based on additional conditions, as long as those additional conditions only impact the same train represented by the surrogate. The RICT calculation will need to be revised based on additional conditions that could impact the other train and therefore take the other train out of service in the PRA given the conservative choice of surrogates described above. This would appear as a functional loss in the PRA. However, this is only an artifact of the PRA, based on bounding assumptions, and will not represent an actual functional loss in the plant, which would be limited by TS .

APLA-RAl-9 (Audit Question 13) - Surrogate for TS 3.6.2 Condition C In Enclosure 1 of the LAR, Table E1-1, for TS 3.6.2, Condition C, "One or more containment air locks inoperable for reasons other than Conditions A or B," states that the PRA success criteria is not modeled for the containment airlock and that, "The failure of the model logic for containment penetrations will be used as a surrogate to conservatively bound the risk increase associated with this function as permitted by NEI 06-09."

a) Provide additional details on the surrogate(s) used (internal events PRA, and fire PRA) for TS 3.6.2 condition C.

i. Include in the discussion the impact of this surrogate on large early release calculations compared to the airlock.

ii. Briefly describe the effect of the failure of early containment isolation (i.e., plant response to the failure of the modeled pathway).

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 11 of 19 b) Provide justification that the surrogate(s) adequately captures configuration risk, is conservative and bounds the effect of an inoperable containment airlock door (internal events PRA, and fire PRA).

NextEra Response:

a) Basic events U1-Cl--CPP-LK---ANY and U2-Cl--CPP-LK---ANY are selected as the surrogates for containment airlocks inoperable via TS 3.6.2 . These basic events represent containment failure via penetrations, through which leakage limits are assumed to be exceeded. While there are no basic events representing this same leakage through an airlock, the functional impact to the PRA is equivalent because source terms are not included in the model and therefore the resolution of the PRA provides no distinction between these two failure mechanisms. This assumed failure (the airlock or the surrogate) leads to a large release. The logic requires core damage (Level 1 sequences) and Level 2 specific logic from the containment event tree, such that progression will lead to RCS/containment conditions for an early release.

The modeling of surrogates for this function is the same in the internal events and fire PRA models.

b) The surrogate is one basic event (per unit) that is modeled to fail containment. Therefore, it is conservative to use this event as a surrogate for TS 3.6.2, while adequately representing the potential impact of having one or more airlocks inoperable.

APLA-RAl-10 (Audit Question 14) - Surrogate for TS 3.6.3 Conditions A and C In Enclosure 1 of the LAR, Table E1-1, for TS 3.6.3, Conditions A and C for one or more penetration flow paths with one containment isolation valve inoperable, states that the PRA success criteria is not modeled for these containment penetrations and that, "The failure of the model logic for containment penetrations will be used as a surrogate to conservatively bound the risk increase associated with this function as permitted by NEI 06-09."

a) Provide additional details on the surrogate(s) used (internal events PRA, and fire PRA) for TS 3.6.3 conditions A and C. Clarify which modeled pathways will be used as a surrogate for each of the system isolation functions affected .

b) Provide justification that the surrogate(s) adequately captures configuration risk, is conservative and bounds each of the isolation functions (internal events PRA, and fire PRA).

NextEra Response:

a) Table E1-1 in Enclosure 1 requires some clarification : The table identifies containment penetrations as not modeled in the PRA; however, there is logic associated with penetrations; for example, gates U 1-GCl 1110 and U1-GCl1200.

For TS 3.6.3, basic events U1-Cl--CPP-LK---ANY and U2-Cl--CPP-LK---ANY are selected as the surrogates to represent one or more penetrations inoperable. These basic events represent containment failure via penetrations, through which leakage limits are assumed to be exceeded. The functional impact to the PRA is equivalent because source terms are not included in the model and therefore the resolution of the PRA provides no distinction between (large) penetration pathway failures.

This assumed failure leads to a large release. The logic requires core damage (Level 1 sequences) and Level 2 specific logic from the containment event tree, such that progression will lead to RCS/containment conditions for an early release.

The modeling of surrogates for this function is the same in the internal events and fire PRA models.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 12of19 b) The surrogate is one basic event (per unit) that is modeled to fail containment. Therefore, it is conservative to use this event as a surrogate for TS 3.6.3, while adequately representing the potential impact of having one or more penetrations inoperable. The TS condition does not necessarily lead to a condition where there are no other protections against release, but in these cases, the chosen surrogate conservatively implies that the penetration allows for a direct path to the environment. The model includes containment isolation logic separate from the surrogate that includes redundancy and could therefore allow for reduced conservatism if necessary.

Probabilistic Risk Assessment Licensing Branch C (APLC) Questions APLC-RAl-1 (Audit Question 18) - Calculation of Seismic CDF Section 2.3.1, Item 7, of NEI 06-09-A, states that the "impact of other external events risk shall be addressed in the RMTS program," and explains that one method to do this is by "performing a reasonable bounding analysis and applying it along with the internal events risk contribution in calculating the configuration risk and the associated RICT." The NRC staffs safety evaluation for NEI 06-09 (Reference 5) states that

[w]here PRA models are not available, conservative or bounding analyses may be performed to quantify the risk impact and support the calculation of the RICT."

In Enclosure 4 of the LAR, Section 2.2, the licensee provides its seismic core damage frequency (SCDF) penalty value of 6.24E-6/year for use in this application based on the plant-specific seismic hazard curves submitted by the licensee in response to the NRC's post-Fukushima actions. However, the licensee did not provide information on the plant-level high confidence of low probability of failure (HCLPF) and the composite variability in the plant-level acceleration capacity (~c) values used for SCDF estimate in the LAR.

The NRC staff noted that the licensee's calculation PBN-BFJR-14-013, "Point Beach Seismic CDF Estimate," in the audit portal provides information on the HCLPF and ~c values and how they are determined and used in estimating the SCDF.

Provide on the docket a summary of the HCLPF and ~c values used for SCDF penalty estimate for this application with justification that these values are the best-available representation of the plant's seismic capacity.

NextEra Response :

The calculation of seismic CDF for Point Beach Nuclear Plant is documented in PBN-BFJR-14-013, Revision 0. This calculation applies a bounding approach that convolves the seismic hazard curve for Point Beach with a plant-level fragility curve calculated using the data and methodology presented in NRC Report Gl-199 and its appendices.

According to Gl-199, Appendix C, the PBN-specific High Confidence of Low Probability of Failure (HCLPF) is 0.16g, where g is the acceleration due to gravity. For PBN, the safety evaluation in Gl-199 assumes a composite variability ((3c) of 0.45. Since the publication of Gl-199, no significant plant modifications have been made at Point Beach that would negatively impact the site's capability to withstand seismic events, and therefore the HCLPF and composite variability values from Gl-199 are still applicable to the Po.int Beach seismic analysis.

The HCLPF of 0.16g and {3c of 0.45 are used to calculate the plant-level fragility curve. A stepwise integration is then performed using the 2013 EPRI seismic hazard curve from the Point Beach Seismic Hazard and Screening Report (NRC 2014-0024, ML14090A275) and the plant-level fragility to calculate a bounding seismic CDF value of 6.24E-06 per year.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 13of19 APLC-RAl-2 (Audit Question 19) - Calculation of Seismic LERF As indicated in the NRC staffs SE for NEI 06-09-A, other sources of risk (i.e., seismic and other external events) must be quantitatively assessed if they contribute significantly to configuration-specific risk. The SE for NEI 06-09, also states that bounding analyses or other conservative quantitative evaluations are permitted where realistic PRA models are unavailable.

In Enclosure 4 of the LAR, Section 2.2, the licensee used a ratio of 0.042 based on the LERF to CDF from the internal events PRA model to estimate seismic LERF (SLERF). However, the licensee did not provide justification for why the ratio of LERF to core damage frequency (CDF) for seismic events should be the same as that from internal events. Based on its review of not only seismic PRAs but also seismic LERF penalties for RICT applications, the NRC staff has noted that the LERF-to-CDF ratio for seismic events can be significantly higher than the ratio for internal events and is typically much higher than 4.2% due to the unique nature of seismically induced failures . It is unclear that the estimated SLERF based on this ratio can be considered a conservative or bounding value. Therefore, the licensee is requested to address the following :

a) Justify that the SLERF provided in the LAR to support RICT calculations for Point Beach is conservative or bounding . Include the rationale that the use of a ratio derived from the internal events is conservative or bounding for seismically induced events, given that random events in internal events PRA do not necessarily capture seismically induced failures that uniquely contribute to SLERF.

b) If the approach to estimating SLERF cannot be justified as bounding for this application in response to part (a) above, then provide, with justification, the conservative or bounding SLERF penalty for use in RICT calculations.

NextEra Response:

Subsequent to the submittal of the LAR, the approach used to calculate a conservative, bounding value for PBN's seismic LERF was revised . This approach determines the seismic LERF (SLERF) by including a second convolution of the plant-level fragility curve that was used to calculate seismic CDF (SCDF).

The SCDF calculation proceeds by convolving the seismic hazard curve with the plant-level fragility as described in PBN-BFJR-14-013. A High Confidence of Low Probability of Failure (HCLPF) value of 0.16g, in conjunction with an assumed composite variability (/3c) of 0.45 , is used to compute the plant-level fragility curve. These HCLPF and composite variability values correspond to a plant-level median capacity of Am = 0.45g. The plant seismic hazard curve (NRC 2014-0024, ML14090A275) is divided into bins according to its ordinate (the ground level acceleration in terms of g) to obtain a seismic initiating event frequency for each bin . The frequency for each bin is then multiplied by the plant-level fragility at the bin interval to calculate a SCDF for each bin. The SCDF values for all bins are then summed to obtain the total estimate of SCDF.

The revised SLERF calculation is an extension of the SCDF calculation. It is conservatively assumed that an additional plant-level failure is required following core damage to result in large early release during a seismic event. Therefore, adding an additional convolution of the plant-level fragility curve to the existing SCDF calculation provides a conservative, bounding estimate of SLERF.

The calculation results in an SLERF value of2.77E-6, which is 44.38% of the SCDF value. Table APLC-19-1 shows the parameters used in the SCDF and SLERF calculation, and Table APLC-19-2 shows the results of this calculation.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 14of19 Table APLC-19-1: Input parameters used to calculate the fragility curves used for the seismic CDF and seismic LERF calculation SCDF Parameters SLERF Parameters (Plant-Level): (Plant-Level):

HCLPF 0.16g HCLPF 0.16g

{3c 0.45 /3c 0.45 Am 0.45g Am 0.45g Table APLC-19-2: The calculation of seismic CDF and seismic LERF SCDF Calculation SLERF Calculation Accel. Bin Cond. Failure Prob. Cond. Failure Prob.

Bin Freq. CDF Estimate LERF Estimate 0.002 1.53E-02 1.15E-33 1.76E-35 1.15E-33 2.03E-68 0.007 4.23E-03 1.10E-20 4.67E-23 1.10E-20 5.15E-43 0.012 1.66E-03 4.00E-16 6.65E-19 4.00E-16 2.66E-34 0.021 1.68E-03 4.86E-12 8.17E-15 4.86E-12 3.97E-26 0.039 5.67E-04 2.74E-08 1.55E-11 2.74E-08 4.26E-19 0.061 2.02E-04 4.48E-06 9. 05E-10 4.48E-06 4.06E-15 0.087 7.29E-05 1.30E-04 9.49E-09 1.30E-04 1.24E-12 0.122 5.27E-05 1.86E-03 9.82E-08 1.86E-03 1.83E-10 0.212 3.21 E-05 4.72E-02 1.52E-06 4.72E-02 7.15E-08 0.387 6.62E-06 3.69E-01 2.44E-06 3.69E-01 9.00E-07 0.612 1.82E-06 7.53E-01 1.37E-06 7.53E-01 1.03E-06 0.866 5.07E-07 9.27E-01 4.70E-07 9.27E-01 4.36E-07 1.225 2.55E-07 9.87E-01 2.52E-07 9.87E-01 2.48E-07 2.121 7.48E-08 1.00E+OO 7.48E-08 1.00E+OO 7.48E-08 3.873 5.10E-09 1.00E+OO 5.10E-09 1.00E+OO 5.10E-09 6.124 6.51 E-10 1.00E+OO 6.51 E-10 1.00E+OO 6.51E-10 8.66 1.05E-10 1.00E+OO 1.05E-10 1.00E+OO 1.05E-10 10 3.93E-1 1 1.00E+OO 3.93E-11 1.00E+OO 3.93E-11 Total SCDF: 6.24E-06 Total SLERF: 2.77E-06 Ratio: 44.38%

APLC-RAl-3 (Audit Question 20) - Evaluation of Seismic Induced Loss of Offsite Power Section 2.3.1, Item 7, of NEI 06-09-A, states that the "impact of other external events risk shall be addressed in the RMTS program ," and explains that one method to do this is by "performing a reasonable bounding analysis and applying it along with the internal events risk contribution in calculating the configuration risk and the associated RICT." The NRC staffs SE for NEI 06-09 states that " [w]here [probabilistic risk assessment] PRA models are not available, conservative or bounding analyses may be performed to quantify the risk impact and support the calculation of the RICT. "

In Enclosure 4 of the LAR, Section 2.2, the licensee did not address the incremental risk associated with seismic-induced loss of offsite power (LOOP) that may occur following the design basis seismic event. The

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page15of19 accident scenarios associated with seismically induced (and therefore unrecoverable) LOOP frequency could already be addressed to some extent in the internal events PRA for unrecovered LOOP events, but this is not explained either.

Demonstrate that seismically induced LOOP will have an inconsequential impact on the RICT calculations.

NextEra Response:

In response to this question, additional discussion and calculations are provided below to address the consequences of seismically induced LOOP on the RICT program calculations. The approach taken for the below discussion and calculations is the same that has been applied in previous LARs in response to the NRC Staffs questions about the topic of seismically induced LOOP. The annual frequency of seismically induced LOOP for Point Beach is estimated and compared to the frequency estimate of non- recovered LOOP from the Point Beach internal events PRA.

The Point Beach mean seismic hazard data is that provided by EPRI, submitted to the NRC in 2013 following a request for information in response to the Fukushima incident, and is contained in PBN-BFJR- 14-013 which calculates the Point Beach seismic CDF. The methodology applied for calculating seismic CDF in PBN-BFJR-14-013 is adopted here to estimate the frequency of seismically induced LOOP.

Table A-0-4 of the RASP Handbook, Volume 2 (NRC ADAMS Accession No. #ML17349A301) provides a median capacity (Am) for offsite power of 0.3g that is based on the seismically induced failure of ceramic insulators in the offsite AC power distribution system. This value is used to calculate a fragility curve representing seismically induced LOOP according to Equation 2 of PBN-BFJR-14-013.

Convolving the LOOP fragility curve with the seismic hazard curve and summing over all frequency bins yields an estimated seismic LOOP frequency of 1.58E-05 per year. Table APLC-20-1 shows the details of the calculation of seismically induced LOOP .

Table APLC-20-1: Calculation of the seismically induced LOOP frequency using the Point Beach seismic hazard curve (cond. failure prob) and the calculated seismic LOOP fragility (bin freq.) curve.

Seismic LOOP Accel. Bin Bin Freq. Cond. Failure Prob.

Frequency (/yr) 0.002 2.38E-02 4.25E-29 6.50E-31 0.007 8.51 E-03 3.39E-17 1.43E-19 0.012 4.28E-03 4.24E-13 7.04E-16 0.021 2.62E-03 1.72E-09 2.88E-12 0.039 9.36E-04 2.90E-06 1.64E-09 0.061 3.69E-04 2 .00E-04 4.04E-08 0.087 1.67E-04 2.97E-03 2.17E-07 0.122 9.41 E-05 2.28E-02 1.20E-06 0.212 4.14E-05 2.20E-01 7.07E-06 0.387 9.28E-06 7.14E-01 4.73E-06 0.612 2.66E-06 9.43E-01 1.72E-06 0.866 8.43E-07 9.91 E-01 5.02E-07 1.225 3.36E-07 9.99E-01 2.55E-07 2.121 8.07E-08 1.00E+OO 7.48E-08 3.873 5.89E-09 1.00E+OO 5.10E-09

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 16of19 6.124 7.95E-10 1.00E+OO 6.51E-10 8.66 1.44E-10 1.00E+OO 1.05E-10 10 3.93E-11 1.00E+OO 3.93E-11 Total Seismic LOOP 1.58E-05 Freq. (/vr):

The Point Beach full-power internal events PRA models LOOP from plant-centered, switchyard-centered, grid-related, and weather-related events. Based on the Point Beach internal events PRA, the total LOOP initiating event frequency is 2.74E-02 per year. As a seismically induced LOOP is assumed to be unrecoverable within the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months PRA mission time, a comparison must be made to the frequency of 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months non-recovered LOOP events in the internal events PRA. Table APLC-20-2 below indicates the initiating event frequencies for plant-centered, switchyard-centered, grid-related, and weather-related events (taken from the Initiating Events Notebook, PRA 2.0), as well as the minimum non-recovery probability factor for each type of LOOP (also taken from PRA 2.0 and the internal events recovery rule file for LOOP recovery) . The rightmost column calculates the total frequency of 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months non-recovered LOOP events, as the product of the LOOP initiator frequency and the non-recovery probability, as well as the plant capacity factor (0.91 ). This is conservatively taken as the Unit 2 capacity factor applied in the PRA model (Data Analysis Notebook, PRA 4.0), which is slightly smaller than the Unit 1 capacity factor (0.93). The use of the minimum non-recovery probability factors is conservative for the purpose of this comparison to the seismically induced LOOP frequency, as it produces the lowest possible bound on the frequency of 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months non-recovered LOOP events . The resulting lower bound on the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months non- recovered LOOP frequency is 1.63E-03 per year.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months non-recovered seismically induced LOOP frequency of 1.58E-05 is approximately two orders of magnitude lower than the minimum possible 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months non-recovered LOOP frequency already addressed in the full-power internal events PRA. This indicates that the frequency of challenging LOOP events is already captured in the internal events PRA, which is explicitly used for the RICT program calculations, and that seismically induced LOOP events will have an inconsequential impact on the RICT program calculations.

Table APLC-20-2: Loss of offsite power (LOOP) non-recovery frequency for the Point Beach internal events PRA.

PBN PRA LOOP PBN Minimum Prob. of PBN PRA 24 hr. Non-LOOP Contributor Initiator Non-Rec. of Offsite AC Recovered LOOP Frequency (/yr) by 24 hrs. Frequency (/yr)

Grid-Centered 5.40E-03 2.06E-02 1.02E-04 Switchyard-Centered 1.33E-02 2.06E-02 2.50E-04 Plant-Centered 2.97E-03 3.35E-02 9.08E-05 Weather-Related 5.69E-03 2.29E-01 1.19E-03 Total 1.63E-03 APLC-RAl-4 (Audit Question 21) - Plant Configuration-Specific Considerations for External Events Section 2.3.1 , Item 7, of NEI 06-09-A, states that the "impact of other external events risk shall be addressed in the RMTS program," and explains that one method to do this is by documenting prior to the RMTS program that external events that are not modeled in the PRA are not significant contributors to configuration risk. The NRC staffs SE for NEI 06-09 states that "[o]ther external events are also treated quantitatively, unless it is demonstrated that these risk sources are insignificant contributors to configuration-specific risk."

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 17of19 In Enclosure 4 of the LAR, Sections 2.1 and 2.3, the licensee concluded that all external hazards except seismic are screened from the RICT program. However, the licensee did not include a discussion if these hazards can be screened from plant's configuration-specific risk considered in the LAR.

Confirm that all external hazards are insignificant contributors to the configuration-specific risk considered in the application . If not, consider a conservative or bounding analysis to quantify the risk from these external hazards for specific configurations in the proposed RICTs and support the calculation of the RICTs.

NextEra Response:

Table E4-1 in Enclosure 4 of the LAR provides screening dispositions for external hazards with respect to the RICT program. All external hazards listed in this table are judged to screen from consideration in the RICT program. The screening criteria applied to the external hazards in Table E4-1 are described in Table E4-2 in Enclosure 4 of the LAR.

It is assumed that if the external hazard was screened from requiring analysis in the PRA model/s, then by extension the hazard would therefore have no impact on configuration-specific plant risk. If a hazard was screened on a basis that includes an assumption about plant configuration, then that hazard should be further considered for potential impacts on configuration-specific risk. Furthermore, any hazards that are screened on the basis of being incredible or not applicable to Point Beach based on location, weather, or other environmental conditions, are automatically screened from consideration for configuration-specific risk impacts.

Each of the hazards from Table E4-1 is either screened from the PRA model as described above or is factored into the configuration-specific plant risk by being included implicitly in an existing component of the PRA model (for example, animal infestation biological events, forest fires, frost, hail, ice cover, lightning, and snow, are included implicitly in the LOOP initiating events modeled in the PRA).

Technical Specifications Branch (STSB) Questions STSB-RAl-1 (Audit Question 22)

The NRC staff noted the following editorial issues in Attachment 3 of the LAR (bases mark-up):

For TS 3.3.1, Actions Q.1 and Q.2, the licensee inserted the phrase "allowed by Condition Y" in between "6" and "hours". Staff believes "allowed by Condition Y" should be inserted after "6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ". Confirm and correct.

NextEra Response:

NextEra agrees that the insertion "allowed by Condition Y" should follow the phrase "6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ". The corresponding TS Bases markup page has been modified accordingly and is included in Attachment 2, Revised Technical Specification Bases Pages (markup), of this RAI response.

For TS 3.3.2, Actions C1, C.2.1, and C.2.2, there appears to be a typo where "Seabrook" is referenced instead of "Point Beach". Confirm and correct.

NextEra Response:

NextEra agrees that the insertion should refer to the "Point Beach PRA model". The corresponding TS Bases markup page has been modified accordingly and is included in Attachment 2 of this RAI response.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 18of19

For TS 3.3.2.D.1, D.2.1, and D.2.2, there appears to be a typo where "Seabrook" is referenced instead of "Point Beach". Confirm and correct.

NextEra Response:

NextEra agrees that the insertion should refer to the "Point Beach PRA model". The corresponding TS Bases markup page has been modified accordingly and is included in Attachment 2 of this RAI response.

For TS 3.5.2.A.1, the term "front stop" was added . Provide justification for adding this language.

NextEra Response:

The term "front stop" was inserted to further distinguish that, pending approval of this amendment request, TS 3.5.2, ACTION A.1, would provide for a front stop Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months which can be extended in accordance with the RICT program. However, NextEra agrees that the insertion is unnecessary and can be removed . The corresponding TS Bases markup page has been modified accordingly and is included in Attachment 2 of this RAI response.

For SR 3.5.2.1 , there appears to be blue font in the text. Provide justification and correct.

NextEra Response:

The corresponding TS Bases markup page for SR 3.5.2.1 has been modified to correct any blue font in the text and is included in Attachment 2 of this RAI response.

For TS 3.6.3.C.1 and C.2, there appears to be blue font in the text. Provide justification and correct.

NextEra Response:

The corresponding TS Bases markup page for TS 3.6.3.C.1 and C.2 has been modified to correct any blue font in the text and is included in Attachment 2 of this RAI response.

For TS 3.7.2, the licensee removed the word "check" from LCO description. Provide justification and correct.

NextEra Response:

The editorial strike-through removing the word "check" from the phrase "non-return check valves" in the LCO 3.7.2 discussion was in error. The corresponding TS Bases markup page has been modified to remove the editorial strike-through and is included in Attachment 2 of this RAI response.

For TS 3.7.5.B.1 , the licensee removed secondary completion time, but there appears to remain a paragraph regarding the 10-day secondary completion time that needs removed . Confirm and correct.

NextEra Response:

NextEra agrees that the third paragraph of TS 3.7 .5, ACTION B.1, should be removed since it further describes how the second Completion Time proposed for removal is implemented. The corresponding TS Bases markup page has been modified to remove the third paragraph of TS 3. 7.5, ACTION B.1 and is included in Attachment 2 of this RAI response .

For TS 3.7. 7 applicability , there appears to be blue font in the text. Provide justification and correct.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Enclosure Page 19of19 NextEra Response:

The corresponding TS Bases markup page for TS 3.7.7 has been modified to correct any blue font in the text and is included in Attachment 2 of this RAI response.

STSB-RAl-2 (Audit Question 23)

In Enclosure 1 of the LAR, Table E1-1 for TS LCO 3.3.1 .0, for FU15b "Two Turbine trip - Stop Valve Closure channels", the design success criteria list 2 of 3. Staff notes that Table 3.3.1-1 of TS states that there are 2 required channels, so it appears that the design success criteria should be 1 of 2. Confirm and correct.

NextEra Response:

The design success criteria specified in Table E1-1 for FU 15b, "Two Turbine trip - Stop Valve Closure channels" requires correction. The correct actuation logic for th is reactor trip function is 2 out of 2 in lieu of 2 out of 3 as specified in the LAR since two turbine throttle-stop valves are available of which both must close to trip the reactor. This trip function is blocked below the P-7 and P-9 permissives.

STSB-RAl-3 (Audit Question 24)

NRC staff suggestion for licensee consideration : The proposed administrative controls for the RICT Program in TS 5.5.7 paragraph "e" of Attachment 2 to the LAR was based on the TS markups of TSTF-505, Revision 2, for Point Beach. The NRC staff recognizes that the model SE for TSTF-505, Revision 2, contains improved phrasing for the administrative controls for the RICT Program in TS 5.5. 7 paragraph "e";

namely the phrasing "approved for use with this program" instead of "used to support this license amendment. " In lieu of the.original phrasing in TS 5.5.7 paragraph "e", discuss whether the phrases "used to support Amendment # xxx" or, as discussed in the TSTF-505 model SE, "approved for use with this program" would provide more clarity for this paragraph .

NextEra Response:

NextEra concurs with the use of the revised phrasing for TS 5.5. 7 paragraph "e" provided in the model SE for TSTF-505 , Revision 2. The corresponding TS Section 5.5.7 markup page has been modified accordingly and is included as Attachment 1 of this RAI response.

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Attachment 1 Page 1 of 3 Revised Technical Specification Pages (markup)

(2 pages follow)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5 .7 DELETED

~Add new 5.5.7 from next page I Point Beach 5.5-6 Unit 1 - Amendment No . ~

Unit 2 - Amendment No . ~

!INSERT new Section 5.5.7 I Risk Informed Completion Time Program This program provides controls to calculate a Risk Informed Completion Time (RICT) and must be implemented in accordance with NEI 06-09, "Risk-Informed Technical Specifications Initiative 4b: Risk-Managed Technical Specifications (RMTS) Guidelines," Revision 0-A, November 2006.

The program shall include the following :

a. The RICT may not exceed 30 days;

b. A RICT may only be utilized in MODES 1 and 2;

c. When a RICT is being used, any change to the plant configuration , as defined in NEI 06-09-A, Append ix A, must be considered for the effect on the RICT.

1. For planned changes , the revised RICT must be determined prior to implementation of the change in configuration.

2. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

3. Revising the RICT is not required if the plant configuration change would lower plant risk and would result in a longer RICT.

d. For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:

1. Numerically accounting for the increased possibility of CCF in the RICT calculation, or

2. Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that 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.

e. The risk assessment approaches and methods shall be acceptable to the NRC. The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2.

Methods to assess the risk from extending the Completion Times must be PRA methods used to support this license amendment, or other methods approved by the NRC fo r generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.

... approved for use with this program .

Point Beach Nuclear Plant, Units 1 and 2 L-2023-003 Docket Nos. 50-266 and 50-301 Attachment 2 Page 1 of 34 Revised Technical Specification Bases Pages (markup)

(33 pages follow)

RPS Instrumentation B 3.3.1 BASES ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1 .

In the event a channel's as-found trip setpoint is found nonconservative with respect to the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected.

When the number of inoperable channels in a trip Function exceed those specified in one or other related Conditions associated with a trip Function, then the unit is outside the safety analysis. Therefore, LCO 3.0.3 must be immediately entered if applicable in the current MODE of operation.

Condition A applies to all RPS protection Functions. Condition A addresses the situation where one or more required channels or trains for one or more Functions are inoperable at the same time. The Required Action is to refer to Table 3.3.1-1 and to take the Required Actions for the protection functions affected. The Completion Times are those from the referenced Conditions and Required Actions .

B.1 and 8 .2 Condition B applies to the Manual Reactor Trip in MODE 1 or 2. With one channel inoperable, the inoperable channel must be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . In this condition, the remaining

... or in accordance with the OPERABLE channel is adequate perform the safety function.

Risk Informed Completion The Completion Time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is reasonable considering that there Time Program are two automatic actuation trains and another manual initiation channel OPERABLE, and the low probability of an event occurring during this interval.

If the Manual Reactor Trip Function cannot be restored to OPERABLE status within the allowed 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time, tho unit must be bFought to e MODE in which the mquircmcnt docs not app ly. To achieve this status, he unit must be brought to at least MODE 3 within 6 additional hours. he 6 additional hours to reach MODE 3 is reasonable, based n operating experience, to reach MODE 3 from full power operation in n orderly manner and without challenging unit systems. With the nit in MODE 3, this trip Function is no longer

.......-.C-o-nd-i-ti_o_n_Y_m_u_s_t_b_e--. required to be OPE BLE.

entered and ...

Point Beach B 3.3.1-32 Unit 1 - Amendment No. 201 Unit 2 - Amendment No . ~

RPS Instrumentation

... or in accordance with the B 3.3.1 Risk Informed Completion Time Program.

BASES ACTIONS (continued) A known ino erable channel must be placed in the tripped condition within 1 hou~ . Placing the channel in the tripped condition results in a 1

partial trip condition requiring only one-out-of-two logic for actuation of the two-out-of-three trips and one-out-of-three logic for actuation of the two-out-of-four trips.

If the inoperable channel cannot be placed in the tripped condition within the specified Completion Time , the unit must be placed in a MODE where these Functions are not required OPERABLE. An additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is allowed to place the unit in MODE 3. Six hours is a reasonable time, based o perating experience, to place the unit in MODE 3 from full power in a orderly manner and without challenging unit systems. ...by Condition y

... or in accordance with the E.1 and E.2 Risk Informed Completion Condition E applies to the Underfrequency E us A01 and A02 trip Time Program . function. With one channel inoperable, the i ~operable channel must be placed in the tripped condition within 6 houri . Placing the channel in the tripped condition results in a partial trip condition requiring only one additional channel to initiate a reactor trip above the P-7 setpoint. The

!... time allowed~ 6 Aours to place the channel in the tripped condition is necessary due to plant design requiring maintenance personnel to effect the trip of the channel outside of the Control Room. An additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is allowed to reduce THERMAL POWER to below P-7 if the inoperable channel cannot be restored to OPERABLE status or placed in trip within the specified Completion Time. .......-.b-y_C_o_n.._d-it-io_n_Z_

Allowance of this time interval takes into consideration the redundant capability provided by the remaining redundant OPERABLE channel and the low probability of occurrence of an event during this period that may require the protection afforded by this trip function.

Point Beach B 3.3.1-34 12/19/01

!This page is for information only. No changes are proposed for this page. I RPS Instrumentation B 3.3.1 BASES ACTIONS (continued) H.1 Condition H applies to one inoperable Source Range Neutron Flux trip channel when in MODE 2, below the P-6 setpoint, and performing a reactor startup. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions . With one of the two channels inoperable, operations involving positive reactivity additions shall be suspended immediately.

This will preclude any power escalation . With only one source range channel OPERABLE, core protection is severely reduced and any actions that add positive reactivity to the core must be suspended immediately.

Condition I applies to two inoperable Source Range Neutron Flux trip channels when in MODE 2, below the P-6 setpoint and performing a reactor startup, or in MODE 3, 4, or 5 with the RTBs closed and the Rod Control System capable of rod withdrawal. With the unit in this Condition, below P-6, the NIS source range perform the monitoring and protection functions. With both source range channels inoperable, the RTBs must be opened immediately. With the RTBs open, the core is in a more stable condition .

J.1 and J.2 Condition J applies to one inoperable source range channel in MODE 3, 4, or 5 with the RTBs closed and the Rod Control System capable of rod withdrawal. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With one of the source range channels inoperable, 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is allowed to restore it to an OPERABLE status. If the channel cannot be returned to an OPERABLE status, 1 additional hour is allowed to open the RTBs.

Once the RTBs are open, the core is in a more stable condition.

K.1 and K.2 Condition K applies to the following reactor trip Functions:

Pressurizer Pressure-Low;

Pressurizer Water Level-High; Reactor Coolant Flow-Low (Two Loops);

Undervoltage Bus A01 and A02.

Point Beach B 3.3.1-36 Unit 1 - Amendment No. -2e+

Unit 2 - Amendment No . .ze&

RPS Instrumentation B 3.3.1

... or in accordance with the BASES Risk Informed Completion Time Program.

ACTIONS (continued) With one channel inoperable, the noperable channel must be placed in the tri pp ed condition within 1 hou' ~ Placin g the channel in the tri pp ed condition results in a partial trip condition requiring only one additional channel to initiate a reactor trip above the P-7 interlock and below the P-8 setpoint. These Functions do not have to be OPERABLE below the P-7 interlock because there are no loss of flow trips below the P-7 interlock. An additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is allowed to reduce THERMAL POWER to below P-7 if the inoperable ch nnel cannot be restored to OPERABLE status or placed in trip within he specified Completion Time. ... b y C on d't' 11on Z Allowance of this time interval takes into consideration the redundant capability provided by the remaining redundant OPERABLE channel ,

and the low probability of occurrence of an event during this period that may require the protection afforded by the Functions associated with Condition K.

... or in accordance with the L.1 and L.2 Risk Informed Completion Condition L applies to the Reactor Coolant Flow-Low (Single Loop)

Time Program. reactor trip Function. With one channel inoperable, the inopE rable channel must be placed in the tripped condition within 1 hou) ! If the channel cannot be restored to OPERABLE status or the channel placed

. WI'th.In th e ~ l'l OUF, tl=i en THERMAL POWER must be reduced

.In t rip below the P-8 d ~point within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This places the unit in a MODE where th ~ LCO is no longer applicabl e. This trip Function does

... time allowed , then not have to be CDPERABLE below the P-8 setpoint because other RPS Condition AA must be trip Functions pr ovide core protection below the P-8 setpoint.

entered . Condition AA requires that the ... M.1 and M.2

... or in accordance with the Condition M applies to the RCP Breaker Pcs ition (Single Loop) reactor Risk Informed Completion trip Function. There is one breaker positior device per RCP breaker.

Time Program. With one channel inoperable, the inoperabl i channel(s) must be restored to OPERABLE status within 1 hou' ( If the channel cannot be restored to OPERABLE status within the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , then THERMAL POWER must be reduced below the P-8' ~etpoint within the next

.. .time allowed, Condition 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

AA must be entered and ...

This places the unit in a MODE where the LCO is no longer applicable.

This Function does not have to be OPERABLE below the P-8 setpoint because other RPS Functions provide core protection below the P-8 setpoint.

Point Beach B 3.3.1-37 Unit 1 - Amendment No . .z.84 Unit 2 - Amendment No. ~

RPS Instrumentation B 3.3.1 BASES

... or in accordance with the Risk Informed Completion ACTIONS (continued) N.1 and N.2 Time Program .

Condition N applies to the RCP Breaker Position (Tv o Loop) reactor trip Function. With one channel inoperable, the inop ~ rable channel must be restored to OPERABLE status within 1 haul . If the channel cannot be restored to OPERABLE status iA 1 t"iour, tt"icA THERMAL POWER must be reduced below the P-i ihterlock within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . This places the unit in a MODE w iere the LCO is no longer applicable . This function does not have t) be OPERABLE below the P-7 interlock because there are no loss o flow trips below the P-7 interlock. The Completion Time of 6 hou1 s is reasonable, based on

... within the time allowed, operating experience, to reduce THERMJ L POWER to below the P-7 Condition Z must be interlock from full power in an orderly mar ner without challenging unit systems.

entered and ...

.. .or in accordance with the 0.1and0.2 Risk Informed Completion Condition 0 applies to Turbine Trip on Low Autostop Oil Pressure or on Time Program.

Turbine Stop Valve Closure. With one channel inoperable, the inoperable channel must be placed in the trip condition within 1 haul ~ If placed in the tripped condition , this results in a partial trip condition requiring only one additional channel to initiate a reactor trip. If the ch anne I cannot bere stored to OPERABLE status or placed in the trip

.. .within the time allowed ,

conditiot~4ReA- powe r must be reduced below the P-9 setpoint within Condition BB must be the next hours.

entered and ...

.., or in accordance with the P.1 and P.2

... Condition Y must be entered and .. .

Risk Informed Completion Condition P applies t o the SI In ut from ESFAS reactor trip and the Time Program, ..

RPS Automatic Tri~ DES 1 and 2. These actions address the train orientation or these Functions. With one train

.inoperable, 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 7are allowe to restore the train to OPERABLE status (Required Action P .1) or he unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (Required Action P.1) is reasonable considering that in this Condition , the remaining OPERABLE train is adequate to perform the safety function and given the low probability of an event during this interval. The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (Required Aetiol'l P.2) is reasonable, based on operating experience, td >each MODE 3 from full power in an orderly manner and without challen iing unit systems .

... allowed by Condition Y ... The Required Actions have been modified by a Note that allows bypassing one train for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for surveillance testing, provided the other train is OPERABLE.

Point Beach B 3.3.1-38 Unit 1 - Amendment No. ~

Unit 2 - Amendment No . ~

RPS Instrumentation

... Condition Y must .. , or in accordance with the Risk be entered and ... Informed Completion Time Program, ...

BASES ACTIONS (continued) Q 1 and Q.2 ... allowed by Condtion Y ...

C ndition Q appli to the TBs in MODES 1 and 2. With one RTB in erable, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1s allowe to restore the RTB to OPERABLE status o the unit must be placed i MODE 3 with in the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable , based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 0 hour0 days 0 hours 0 weeks 0 months Cor:npletion Times are equa l to the time allowed by LGO 3.0.3 for shutdown actions in the event ef a eemplete less of RPS Function . Piecing the un it in MODE 3 removes the requ irement for this particu lar Function.

The Required Actions have been modified by a Note allowing one channel to be bypassed for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months provided the other channel is OPERABLE.

R.1 and R.2 Condition R applies to the P-6 interlock (in MODE 2) and the P-10 interlock. With one or more channels inoperable for one-out-of-two or two-out-of-four coincidence logic, the associated interlock must be verified to be in its requ ired state for the existing unit condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

Verifying the interlock status manually accomplishes the interlock's Function. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is based on operating experience and the minimum amount of time allowed for manual operator actions. The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Completion Times are equal to the time allowed by LCO 3.0.3 for shutdown actions in the event of a complete loss of RPS Function.

S.1 and S.2 Condition S applies to the P-7, P-8, and P-9 interlocks. With one or more channels inoperable for one-out-of-two or two-out-of-four coincidence logic, the associated interlock must be verified to be in its required state for the existing unit condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or the unit must be placed in MODE 2 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . These actions are conservative for the case where power level is being raised. Verifying the interlock status manually accomplishes the interlock's Function.

The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is based on operating experience and the minimum amount of time allowed for manual operator actions. The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience , to reach MODE 2 from full power in an orderly manner and without challenging unit systems.

Point Beach B 3.3.1-39 Unit 1 - Amendment No. ~

Unit 2 - Amendment No. ~

RPS Instrumentation B 3.3.1 BASES ACTIONS (continued) T.1 and T.2 Condition T applies to the RTBs and the RTB Undervoltage and Shunt Trip Mechanisms -in MODES 3, 4, or 5 with the RTBs closed and the Rod Control System capable of rod withdrawal.

With one trip mechanism or RTB inoperable, the inoperable trip mechanism or RTB must be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . The Completion Time is reasonable considering that the remaining OPERABLE trip mechanism or RTB is adequate to perform the safety function, and given the low probability of an event occurring during this interval.

If the RTB or trip mechanism cannot be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , the unit must be placed in a MODE in which the requirement does not apply. This is accomplished by opening the RTBs within the next hour (49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months total time) . The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months provides sufficient time to accomplish this action in an orderly manner and takes into account the low probability of an event occurring in this interval.

, .. .or in accordance with U.1 and U.2 the Risk Informed ...Condition Y must be entered and ...

Completion Time Program ,.. Condition U applies to the RTB Un :le oltage and Shunt Trip Mechanisms, or diverse trip featun s, in MODES 1 and 2. With one of the diverse trip features inoperabl ~ ) t must be restored to an OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months o the unit must be placed in a MODE where the requirement does not apply. This is accomplished by placing the unit in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (54 fieu Fs tet~ I ti111e) .

The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is a reasonable time , based on operating experience, to reach DE 3 from full power in an orderly manner and without challenging nit systems .

... allowed by Condition Y ...

With the unit in MODE 3, Condition T would apply to any inoperable RTB trip mechanisms. The affected RTB shall not be bypassed while one of the diverse features is inoperable except for the time required to perform maintenance to one of the diverse features. The allowable time for performing maintenance of the diverse features is 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for the reasons stated under Condition Q.

The Completion Time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is reasonable considering that in this Condition there is one remaining diverse feature for the affected RTB, and one OPERABLE RTB capable of performing the safety function and given the low probability of an event occurring during this interval.

Point Beach B 3.3.1-40 Unit 1 - Amendment No. ~

Unit 2 - Amendment No. 296-

ESFAS Instrumentation B 3.3.2 BASES ACTIONS B.1, B.2.1 and B.2.2 (continued)

Condition B applies to manual i'nitiation of:

SI; and

.. , or in accordance with the Risk

Containment Isolation. Informed Completion Time Program, ...

If a channel is inoperable, 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months are allowed to return it to OPERABLE status. The specified Completion Time is reasonable considering that there are two automatic actuation trains and another manual initiation train OPERABLE for each Function, and the low probability of an event occurring during this interval. If the channel cannot be restored to OPERABLE status1 ~ he unit must be placed in a MODE in which the LCO does not appl 1

This is done by placing the unit in at least MODE 3 within an addi ional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months total time) and in MODE 5 within an additipnal 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months (84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months total time). The allowable Completion Tin ,es are reasonable, based on operating experience, to reach the req W ir unit conditions from full power conditions in an orderly manner an without challenging unit systems .

.. , Condition L must ... of Condition L. ..

~-----------------'

be entered and ... C.1, C.2.1 and C.2.2 Condition C applies to the automatic actuation logic and actuation

. . . - - - - - - - - - - - - - - - - - - , relays for the following functions :

The COMPLETION TIME of Condition C is modified by a note

SI; which, due to limitations in the Point Beach PRA model, prohibits

Containment Spray; and a Completion Time extension in .. , or in accordance with the Risk accordance with the a Risk

Containment Isolation. Informed Completion Time Program , ...

Informed Completion Time for If one train is inopej~ble, 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months are allowed to restore the train to Function 2b, Containment Spray - OPERABLE statu;f The specified Completion Time is reasonable Automatic Actuation Logic and considering that there is another train OPERABLE, and the low Actuation Relays, of Technical probability of an event occurring during this interval. If the train Specification 3.3.2, Table 3.3-2. cannot be restored to OPERABLE statu the unit must be placed in

....____ _ _ _ _ _ _ _ _ _ _ _____. a MODE in which the LCO does not appl . This is done by placing the unit in at least MODE 3 within an ad itional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months total time) and in MODE 5 within an addi ional 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months (42 hours4.861111e-4 days 0.0117 hours 6.944444e-5 weeks 1.5981e-5 months total time). The Completion Times are r asonable, based on operating experience, to reach the requi d unit conditions from full power conditions in an orderly ma ner a d without challenging unit systems.

. .. of Condition L. ..

. . , Condition L must 1----------------~

be entered and ...

Point Beach B 3.3.2-28 Unit 1 - Amendment No . ~

Unit 2 - Amendment No. 2-e&

ESFAS Instrumentation B 3.3.2 BASES D.1, D.2.1 and D.2 .2 The COMPLETION TIME of Condition ACTIONS (continued) D is modified by a note which, due to Condition D applies to : limitations in the Point Beach PRA model, prohibits a Completion Time

Containment Pressure-High; extension in accordance with the Risk Informed Completion Time for

Pressurizer Pressure-Low; Function 2c, Containment Spray -

Containment Pressure High-High, of

Steam Line Pressure-Low; Technical Specification 3.3.2, Table

Containment Pressure-High High ; ._3_.3_-_2_*-----~-------

High Steam Flow Coincident With Safety Injection Coin ident With Tav9 -Low;

High High Steam Flow Coincident With Safety Injection

., or in accordance with the Risk SG Water level-Low Low; and nformed Completion Time Program, ...

SG Water level-High.

If one channel is inoperable, 1 houl fa allowed to restore th channel to OPERABLE status or to place it in the tripped condition. lacing the channel in the tripped condition is necessary to maintain a logic configuration that satisfies redundancy requirements .

... the time allowed requires entering Condition Mand ... Failure to restore the inoperable cha nel to OPERABLE status or place it in the tripped condition with i 1 f:iou r requires the unit be placed in MODE 3 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

... of Condition M ...

The allowed Completion Time are reasonable , based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 4, these Functions are no longer required OPERABLE.

Point Beach B 3.3.2-29 Unit 1 - Amendment No. ~

Unit 2 - Amendment No. -:2B6-

ESFAS Instrumentation B 3.3.2 BASES ACTIONS E.1, E.2.1, and E.2.2 (continued)

Condition E applies to manual initiation of Containment Spray. If one or both channels are inoperable, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to return the inoperable channel(s) to OPERABLE status. The Completion Time of one hour is reasonable considering that there are OPERABLE automatic actuation functions credited to perform the safety function and the low probability of an event occurring during this interval. If the inoperable channel(s) cannot be restored to OPERABLE status, the unit must be placed in a MODE in which the LCO does not apply.

This is done by placing the unit in at least MODE 3 within an additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months total time) and in MODE 5 within an additional 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months (37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months total time). The allowable Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

F F dF .. . within the time allowed ,

1 21 22

* * * *an *

Condition M must be entered and .. .

.. , or in accordance with the Condition F applies to Manual Initiation of Steam Line Isolation.

Risk Informed Completion Time Program, ... If a channel is inoperable, 1 hou s allowed to return it to an OPERABLE status. The Completion Time of one hour is reason considering the low probability of an event occurring during this interval. If the Function cannot be returned to OPERABLE status, the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the requir d unit conditions from full power in an orderly manner and witho t challenging unit systems. In MODE 4, the unit does not have any a alyzed transients or conditions that require the explicit use of the pr tection functions noted above .

'-----------i . * .

of Condition M ...

G.1. G.2.1, and G.2.2 Condition G applies to the automatic actuation logic and actuation relays for the Steam Line Isolation, Feedwater Isolation, Condensate

.. , or in accordance with the Isolation and AFW actuation Functions.

Risk Informed Completion Time Program, ... If one train is inoperable, 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months sVare allowed to restore the train to OPERABLE status. The Completion Time for restoring a train to OPERABLE status is reasonable considering that there is another train OPERABLE, and the low probability of an event occurring during this interval. If the train cannot be returned to OPERABLE status the unit must be brought to MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and N ~ DE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion

... within the time allowed ,

Condition M must be entered and ... - B 3.3.2-30 Unit 1 - Amendment No. -2B+

Unit 2 - Amendment No. ~

ESFAS Instrumentation B 3.3.2 BASES

... of Cond ition M ...

ACTIONS Times re reasonable, based on operating experience, to reach the (continued) required unit conditions from full power conditions in an orderly manner and without challenging unit systems. Placing the unit in MODE 4 removes all requirements for OPERABILITY of the protection channels and actuation functions. In this MODE, the unit does not have analyzed transients or conditions that require the explicit use of the protection functions noted above.

~-------------~

.. , or in accordance with the Risk H.1 and H.2 Informed Completion Time Program, ...

Condition H applies to the Undervolt ge Bus A01 and A02 Function.

If one channel is inoperable, 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months are allowed to restore one channel to OPERABLE status or place it in the tripped condition. If placed in the tripped condition, this Function is then in a partial trip condition where one-out-of-two logic will result in actu~tion. The-8"'

I... time allowed ... ~ ftettt:s- to place the channel in the tripped condition is necessary due to plant design requiring maintenance personnel to effect the trip of the channel outside of the control room. Failure to restore the inoperable channel to OPERABLE status or place it in the tripped condition withi 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months requires the unit to be placed in MODE 3 within the follo ing 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time of..&'

I... Condition M ... ~ ~ is reason ble, based on operating experience, to reach MODE 3 from full pow r conditions in an orderly manner and without challenging uni systems. In MODE 3, this Function is no longer required OPER BLE.

... the time allowed requires ~--------'

entry into Condition K and 1.1, 1.2.1 and 1.2.2 Condition I applies to the Pressurizer Pressure SI Block.

With one or more channels inoperable, the operator must verify that the interlock is in the required state for the existing unit condition.

This action manually accomplishes the function of the block.

Determination must be made within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is equal to the time allowed by LCO 3.0.3 to initiate shutdown actions in the event of a complete loss of ES FAS function. If the block is not in the required state (or placed in the required state) for the existing unit condition, the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. Placing the unit in MODE 4 removes all requirements for OPERABILITY of the Pressurizer Pressure SI block.

Point Beach B 3.3.2-31 Unit 1 - Amendment No . .ze.+

Unit 2 - Amendment No. ~

Pressurizer PORVs B 3.4.11 BASES ACTIONS (continued) B.1, B.2, and B.3 If one PORV is inoperable and not capable of being manually cycled, it must be either restored, or isolated by closing the associated block valve and removing the power to the associated block valve. The Completion Times of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months are reasonable, based on challenges to the PORVs during this time period, and provide the operator adequate time to correct the situation. If the inoperable valve cannot be restored to OPERABLE status, it must be isolated within the specified time.

Because there is at least one PORV that remains OPERABLE, an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is provided to restore the inoperable PORV to OPERABLE status'.!\ If the PORV cannot be restored within this additional time, the plant must be brought to a MODE in which the LCO

.. , or in accordance with the does not apply, as equired by Condition D.

Risk Informed Completion C.1 and C.2 Time Program, ..

If one block valve is inoperable, then it is necessary to either restore the block valve to OPERABLE status within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or place the associated PORV in manual control. The prime importance for the capability to close the block valve is to isolate a stuck open PORV. Therefore, if the block valve cannot be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , the Required Action is to place the PORV in manual control to preclude its automatic opening for an overpressure event and to avoid the potential for a stuck open PORV at a time that the block valve is inoperable . The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable, based on the small potential for challenges to the system during this time period, and provides the operator time to correct the situation. Because at least one PORV remains OPERABLE, the operator is permitted a Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months +/-o restore the inoperable block valve to OPERABLE status. The time lowed to restore the block valve is based upon the Completion Ti e for restoring an inoperable PORV in Condition B, since the PORVs m y not be capable of mitigating an event if the inoperable block val e is not full open. If the block valve is restored within the Completio Time Qf...

72 l"leurs, the power will be restored to the PORV. If it c nnot be restored within this additional time, the plant must be bro ght to a

.. , or in accordance with the MODE in which the LCO does not apply, as required by ondition D.

Risk Informed Completion Time Program, .. The Required Actions C.1 and C.2 are modified by a Note stating that the Required Actions do not apply if the sole reason for the block valve being declared inoperable is as a result of power being removed to comply with other Required Actions. In this event, the Required Actions for inoperable PORV(s) (which require the block valve power to be removed once it is closed) are adequate to address the condition.

While it may be desirable to also place the PORV(s) in manual control, Point Beach B 3.4.11-4 Unit 1 - Amendment No. Z&i Unit 2 - Amendment No. 2-e6

ECCS - Operating B 3.5.2 BASES APPLICABILITY In MODES 1, 2, and 3, the ECCS OPERABILITY requirements for the limiting Design Basis Accident, a large break LOCA, are based on full power operation . Although reduced power would not require the same level of performance, the accident analysis does not provide for reduced cooling requirements in the lower MODES. The SI pump performance requirements are based on a small break LOCA. MODE 2 and MODE 3 requirements are bounded by the MODE 1 analysis.

This LCO is only applicable in MODE 3 and above. Below MODE 3, the low pressurizer pressure and low steam generator pressure automatic SI signals are manually bypassed by operator control, and system functional requirements are relaxed as described in LCO 3.5.3, "ECCS-Shutdown ."

In MODES 5 and 6, plant conditions are such that the probability of an event requiring ECCS injection is extremely low. Core cooling requirements in MODE 5 are addressed by LCO 3.4.7, "RCS Loops-MODE 5, Loops Filled," and LCO 3.4.8, "RCS Loops-MODE 5, Loops Not Filled." MODE 6 core cooling requirements are addressed by LCO 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation -

High Water Level," and LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level."

ACTIONS With one train inoperable, the inoperable components must be returned to OPERABLE status within 72 hour~ The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on an NRC reliability evaluaticS 1 (Ref. 5) and is a reasonable time

.. , or in accordance with the for repair of many ECCS component~ .

Risk Informed Completion Time Program, ... An ECCS train is inoperable if it is not capable of delivering the limiting design basis analysis flow rate to the RCS or if the train is not capable of supporting recirculation mode operation . Individual components are inoperable if they are not capable of performing their design function or supporting systems are not available.

The LCO requires the OPERABILITY of a number of independent subsystems. Due to the redundancy of trains and the diversity of subsystems, the inoperability of one component in a train does not render the ECCS incapable of performing its function. Neither does the inoperability of multiple components in the same train (e.g. the "A" SI pump and the "A" RHR pump), result in a loss of function for the ECCS .

The intent of this Condition is to maintain a combination of equipment such that a single OPERABLE ECCS train remains available.

Point Beach B 3.5.2-5 10120101

ECCS - Operating B 3.5.2 BASES ACTIONS (continued) An event accompanied by a loss of offsite power and the failure of an EOG can disable one ECCS train until power is restored. A reliability The Risk Informed analysis (Ref. 5) has shown that the impact of having one full ECCS Completion Time Program train inoperable is sufficiently small to justify continued operation for further evaluates the plant 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . 'f'.

risk associated with this With more than one component inoperable such that both ECCS trains Condition to determine an are not available, the facility is in a condition outside design and appropriate Completion Time licensing basis. Therefore , LCO 3.0.3 must be immediately entered .

extension.

B.1 and B.2 If the inoperable trains cannot be returned to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.5.2.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked , sealed , or otherwise secured in position, since these were verified to be in the correct position prior to locking ,

sealing, or securing . A valve that receives an actuation signal is allowed to be in a non-accident position provided the valve will automatically reposition within the proper stroke time. This Surveillance does not require any testing or valve manipulation . Rather, it involves verification that those valves capable of being mispositioned are in the correct position. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

The Surveillance frequency is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include a stationing of a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed .

Point Beach B 3.5.2-6 Unit 1 - Amendment No . -259' Unit 2 - Amendment No . 25-t-

Containment Air Locks B 3.6.2 BASES ACTIONS (continued) B.1, B.2, and B.3 With an air lock interlock mechanism inoperable in one or more air locks, the Required Actions and associated Completion Times are consistent with those specified in Condition A. The Required Actions have been modified by two Notes. Note 1 ensures that only the Required Actions and associated Completion Times of Condition C are required if both bulkheads in the same air lock are inoperable. With both bulkheads in the same air lock inoperable, an OPERABLE isolation boundary is not available. Required Actions C.1 and C.2 are the appropriate remedial actions . Note 2 allows entry into and exit from containment under the control of a dedicated individual stationed at the air lock to ensure that only one bulkhead door and its associated equalization valve is opened at a time (i.e., the individual performs the function of the interlock).

Required Action B.3 is modified by a Note that applies to air lock doors and equalization valves located in high radiation areas and allows these doors and valves to be verified locked closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted.

Therefore, the probability of misalignment of the door or equalization valve, once it has been verified to be in the proper position, is small.

C.1, C.2, and C.3 With one or more air locks inoperable for reasons other than those described in Condition A or B, Required Action C.1 requires action to be initiated immediately to evaluate previous combined leakage rates using current air lock test results. An evaluation is acceptable, since it is overly conservative to immediately declare the containment inoperable if both bulkheads in an air lock are inoperable. In many instances (e.g., only one seal per door has failed), containment remains OPERABLE, yet only 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (per LCO 3.6.1) would be provided to restore the air lock bulkhead to OPERABLE status prior to requiring a plant shutdown . In addition, even with both doors failing the seal test, the overall containment leakage rate can still be within limits.

Required Action C.2 requires that one door and its associated equalization valve in the affected containment air lock must be verified to be closed within the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time. This specified time period is consistent with the ACTIONS of LCO 3.6.1, which requires

.. , or in accordance with the that containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Risk Informed Completion Time Program, ... Additionally, the affected air lock(s) must e restored to OPERABLE status within the 36 hour4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Completion Tim . The specified time period is Point Beach B 3.6.2-5 7130102

Containment Isolation Valves B 3.6.3 BASES ACTIONS (continued) A second Note has been added to provide clarification that, for this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable containment isolation valve. Complying with the Required Actions may allow for continued operation, and subsequent inoperable containment isolation valves are governed by subsequent Condition entry and application of associated Required Actions.

The ACTIONS are further modified by a third Note, which ensures appropriate remedial actions are taken, if necessary, if the affected systems are rendered inoperable by an inoperable containment isolation valve.

In the event the containment isolation valve leakage results in exceeding the overall containment leakage rate, Note 4 directs entry into the applicable Conditions and Required Actions of LCO 3.6.1.

A.1 and A.2 In the event one containment isolation valve in one or more penetration flow paths is inoperable, the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic containment isolation valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured.

For a penetration flow path isolated in accordance with Required Action A.1, the device used to isolate .the penetration should be the closest available one to containment. Required Action A.1 must be completed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, considering the time req(~ed to isolate the penetration and the relative importance of supporting containment OPERABILITY during MODES 1,

.. , or in accordance with the 2, 3, and 4.

Risk Informed Completion Time Program, For affected penetration flow paths that cannot be restored to OPERABLE status within the 4 19our Completion Time and that have been isolated in accordance with Required Action A.1, the affected penetration flow paths must be verified to be isolated on a periodic basis. This is necessary to ensure that containment penetrations required to be isolated following an accident and no longer capable of being automatically isolated will be in the isolation position should an event occur. This Required Action does not require any testing or device manipulation . Rather, it involves verification that those isolation devices outside containment and capable of being mispositioned are in the correct position. The Completion Time of "once per 31 days or

... following isolation ...

Point Beach B 3.6.3-4 11/18/2003

Containment Isolation Valves B 3.6.3 BASES ACTIONS (continued) under administrative control and the probability of thei r misalignment is low.

Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two containment isolation valves. Condition A of this LCO addresses the cond ition of one containment isolation valve inoperable in this type of penetration flow path. .., or in accordance with the Risk Informed Completion C.1 and C.2 Time Program.

With one or mor penetration flow paths with one conta inment isolation valve inoperable the inoperable valve flow path must be restored to OPERABLE stat s or the affected penetration flow path must be isolated . The m thod of isolation must include the use of at least one isolation barrier t at cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated autom tic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration flow path. Required ction C.1 must be completed within the 72-hour Completion Tim . The specified time period is reasonable considering the relative stability of the closed system (hence , reliability) to act as a penetration isolation boundary and the relative importance of maintaining containment integrity during MODES 1, 2, 3, and 4. In the event the affected penetration flow path is isolated in accordance with Required Action C.1, the affected penetration flow path must be verified to be isolated on a periodic basis. This periodic verification is necessary to assure leak tightness of containment and that containment penetrations requiring isolation following an accident are isolated. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Condition C is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with only one containment isolation valve and a closed system. The closed system must meet the requirements of Ref 2. This Note is necessary since this Condition is written to specifically address those penetration flow paths which utilize closed systems as one of the two containment barriers.

LCO 3.6.3 provides no specific action related to the condition of the closed system. An industry interpretation relative to the treatment of a closed system is documented in TSTF-502-T, Technical Specifications Task Force. This traveler discusses the status of a closed system if not intact, the condition must be evaluated as a degraded or nonconforming condition under 10 CFR 50 , Appendix B. Leakage from a closed system may also affect the Operability (Functionality) of the system itself, which may be the subject of other specifications. Leakage from closed systems will be governed by ASME requirements on Code Class 1, 2 and 3 systems , typically described in the Technical Requirements Point Beach B 3.6.3-6 August 2021

MSIVs and Non-Return Check Valves B 3.7.2 BASES LCO This LCO requires that two MSIVs and two non-return check valves in the steam lines are to be OPERABLE. The MSIVs are considered OPERABLE when the isolation times are within limits, and they close on an isolation actuation signal. The steam line non-return check valves are considered to be operable when they are capable of closing in response to reverse flow.

This LCO provides assurance that the MSIVs and non-return check valves will perform their design safety function to mitigate the consequences of accidents that could result in offsite exposures comparable to the 10 CFR 100 (Ref. 3) limits.

APPLICABILITY The MSIVs and non-return check valves must be OPERABLE in MODES 1, 2, and 3, when there is significant mass and energy in the RCS and steam generators.

In MODE 4, normally the MSIVs and non-return check valves are closed, and the steam generator energy is low.

In MODE 5 or 6, the steam generators do not contain much energy because their temperature is below the boiling point of water; therefore, the MSIVs and non-return check valves are not required for isolation of potential high energy secondary system pipe breaks in these MODES .

- .. , or in accordance with the Risk Informed ACTIONS Completion Time Program.

With ore or more valves in a SG flowpath inoperable in MODE 1, action must be taken to restore the flowpath to OPERABLE status within 8 hour~ / Some repairs to the MSIV can be made with the unit hot. The 8 19eur Completion Time is reasonable, considering the low probability of an accident occurring during this time period that would require a closure of the MSIVs or non-return check valves. 1 ,

The MSIVs are containment isolation valves, and ~ s such the applicable Conditions and Required Actions of LC D 3.6.3 must be To prevent a Condition resulting in a loss of function and assure safety system reliability, Condition A is modified by a note which prohibits a Completion Time extension in accordance with the Risk Informed Completion Time Program when an MSIV and non-return valve of the same steam generator flowpath are both inoperable.

Point Beach B 3.7.2-3 UMit 1 11/30/2009 U1 lit 2 11130/2009

ADV Flowpaths B 3.7.4 BASES APPLICABLE critical than the time required to cool down to RHR conditions for this SAFETY ANALYSES event. Thus , the SGTR is the limiting event for the ADVs.

(continued)

The ADVs are equipped with block valves in the event an ADV spuriously fails to close during use.

The ADVs satisfy Criterion 3 of the NRC Policy Statement.

LCO Two ADV flowpaths are required to be OPERABLE. One ADV flowpath is required from each of two steam generators to ensure that at least one ADV flowpath is available to conduct a unit cooldown following an SGTR, in which one steam generator becomes unavailable . The block valves must be OPERABLE to isolate a failed open ADV flowpath. A closed block valve renders its ADV flowpath inoperable.

Failure to meet the LCO can result in the inability to cool the unit to RHR entry conditions following an event in which the condenser is unavailable for use with the Steam Bypass System .

The ADVs are OPERABLE when they are capable of being locally opened and closed through their full range using the valve operator handwheel. The ADVs have a functionality requirement to be capable of remote operation from the Control Room. Remote operation is credited in the SGTR analysis.

APPLICABILITY In MODES 1, 2, and 3, and in MODE 4, when a steam generator is being relied upon for heat removal, the ADVs are required to be OPERABLE.

In MODE 4 when the steam generators are not relied upon for heat removal (residual heat removal system in operation), the RCS and steam generator temperatures have been reduced to a temperature sufficiently below the saturation pressure which corresponds to the steam generator safety valves lift setpoints to preclude radiological releases to the environs as a result of a SGTR.

In MODE 5 or 6, an SGTR is not a credible event. .. , or in accordance with the

..-----lRisk Informed Completion ACTIONS Time Program.

With one required ADV flowpath inope\ Vble, action must be taken to restore OPERABLE status within 7 day . The -1-ey Completion Time Completion Time is reasonable to repa ir an inoperable ADV flowpath, based on the availability of the remaining OPERABLE ADV, the nonsafety grade backup in the Steam Bypass System, and MSSVs, and Point Beach B 3.7.4-2 7/22/2015

AFW System B 3.7.5 BASES ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable AFW pump system. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an AFW pump system inoperable and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after a performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance .

With the turbine driven AFW pump system inoperable due to one inoperable steam supply, or if the turbine driven pump is inoperable for any reason while in MODE 3 immediately following refueling, action must be taken to restore the inoperable equipment to an OPERABLE status within 7 day . The 4a.¥ Completion Time is reasonable, based

.. , or in accordance with the on the following re ans:

Risk Informed Completion Time Program. a. For the inoperability of the turbine driven AFW pump due to one inoperable steam supply, the +-eey-Completion Time is reasonable, since there is a redundant steam supply to the turbine driven AFW pump and the turbine driven pump system is still capable of performing its specified safety function for most postulated events.

b. For inoperability of a turbine driven pump wh ile in MODE 3 immediately subsequent to a refueling, the ~ Completion Time is reasonable due to the minimal decay heat in this situation .

c. For both the inoperability of the turbine driven pump due to one inoperable steam supply and an inoperable turbine driven AFW pump while in MODE 3 immediately following a refueling outage, the 1-ay- Completion Time is reasonable due to the availability of a redundant OPERABLE AFW pump, and due to the low probability of an event requiring the use of the inoperable turbine driven AFW pump.

The second Comp leti on Time for Requ ired Action /\.1 establishes a Iii 1lit 011 ti 1e 111axi111u111 ti11ie allovved fo1 any combination of Conditions to be inoperable during any continuous fa ilure to meet tn is LOO .

The 10 day Completion Time pre*o'ides a limitation time allowed in this specified Condition after disco'o'ery of fa il ure to meet the LCO. This limit is censidernd reasonab le for situations in v;hich multiple Gonelitions are entered comamontly. Tho Al)Jbl connector between 7 elays anel 10 elays dictates tnat both Completion Times app ly simu ltaneously, and tho mere restrictive must be mot.

Point Beach B 3.7.5-6 Unit 1 - Amendment No. -r3tt Unit 1 - Amendment No. -24Z

AFW System B 3.7.5 BASES ACTIONS (continued) Condition A is modified by a Note which limits the applicability of the Condition for an inoperable turbine driven AFW pump in MODE 3 to when the unit has not entered MODE 2 following a refueling. Condition A allows one AFW train to be inoperable for 7 days ~ ice the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time in Condition B. This longer Com1 letion Time is based

.. , or in accordance with the on the reduced decay heat following refueling and I rior to the reactor Risk Informed Completion being critical.

Time Program, ...

.. , or in accordance with the Risk Informed Completion When ore of the required AFW pump systems is inoperable in Time Program, ... MODE 1 2, or 3, for reasons other than Condition A , action must be taken to estore the pump system to OPERABLE status within 72 hour~ ~ This Condition includes loss of two steam supply lines to the turbine driven AFW pump. The 72 19aur Completion Time is reasonable, based on redundant capabilities afforded by the remaining OPERABLE AFW pump system , time needed for repairs, and the low probability of a OBA occurring during this time period.

The second Comp letion Time for Req1::1 ired Aotign B.1 establiah9e a li FA it an tl9e FABXiFALIFA tiFAe ellawed for any coFAbination of Cond itions to be inaperable elurinQ any eonti11uous fai lure to 111 eet ti Jis LOO .

Tl9e 10 elay GaFApletion Tiffie provides a lim itation time all owed in th is speoified Condition after discovery of fa il ure to meet the LGO . Th is li FAit is considered reasonab le for situations in wh ich FAu ltiple Conditions ere entered simultaneo1::1sly. The A~JD oonneotor betv.1een 72 ho1::1rs and 10 day GoFAp letion TiFAes dictate tl9et botl9 GoFAp leti on TiFAes app ly simultaneously, and the more restriotive m1::1st be met.

With the turbine driven AFW pump system inoperable due to one inoperable steam supply and the motor driven AFW pump system inoperable, action must be taken to restore the affected equipment to OPERABLE status within 24 or 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months as described below.

Assuming no single active failures when in this condition, the accident (MSLB) could result in the loss of the remaining steam supply to the turbine driven AFW pump due to the faulted steam generator. In this condition, the AFW system may no longer be able to meet the required flow to the SGs assumed in the safety analysis.

If the motor driven AFW pump system from the opposite unit is not available, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable based on the remaining OPERABLE steam supply to the turbine driven AFW pump, and low probability of an event occurring that would require the inoperable steam supply to be available for the turbine driven AFW pump .

Point Beach B 3.7.5-7 Unit 1 - Amendment No.-2 Unit 1 - Amendment No . '2z1:2""

CC System B 3.7.7 BASES LCO (continued) exchanger establishes the number of required heat exchangers for two unit operation at three . This will provide assurance that at least one CC pump and heat exchanger will be available for post accident operation in the unit undergoing an accident, while also providing assurance that at least one CC pump and heat exchanger will be available for shutdown capability of the non-accident unit.

The isolation of CC from other components or systems not required for safety may render those components or systems inoperable but does not affect the OPERABILITY of the CC System.

APPLICABILITY In MODES 1, 2, 3, and 4, the CC System is a normally operating system, which must be prepared to perform its post accident safety functions, primarily RCS heat removal, which is achieved by cooling the RHR heat exchanger.

In MODE 5 or 6, the OPERABILITY requirements of the CC System are determined by the systems it supports.

In MODE 5 or 6, the CC system is required to be Functional to support RHR. The CC system requires a pump and heat exchanger to provide forced flow and cooling to support the RHR function for decay heat removal .

ACTIONS The Required Actions are modified by a Note indicating that the applicable Conditions and Required Actions of LCO 3.4.6, "RCS Loops-MODE 4," are required to be entered if inoperable CC loop components result in the inoperability of an RHR loop. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components .

.. , or in accordance with the Risk Informed Completion Time Program. If one required CC pump is inoperable (including inoperability o1 any associated piping , valves , and controls required to perform the' afety related function that renders the pump inoperable), action must pe taken to restore the pump to OPERABLE status within 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months sV In this Condition, the remaining OPERABLE CC pump is adequate to perform the heat removal function . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on the redundant capabilities afforded by the OPERABLE pump, and the low probability of a OBA occurring during this period.

The second Completion Time for Requirod Action A. 1 estaelishes a limit ofl H~e maximum tiffie allowed for any coffibination of Conditions to be inoperable during BAY cofltifluous failure to meet ti iis LOO.

The 144 hour0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months Completion Time provides a limitation time allowed in this BASES Point Beach B 3.7.7-4 April 2021

CC System B 3.7.7 ACTIONS (continued) speoified Cond ition after discovery of failure to meet the LCO. Th is limit is considered reasonable for situations in which multiple Conditions are entered concurrently. The Afill oonneotor behveen 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 144 hour0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months dictates that both Completion Times apply simu ltaneously, and the more rnstrictivc must be met.

.. , or in accordance with the Risk Informed Completion Time Program. If one required CC heat exchange is inoperable (including inoperability of any associated piping, valves, c: nd controls required to perform the safety related function that renden the heat exchanger inoperable),

action must be taken to restore the inoperable heat exchanger to OPERABLE status within 72 houri ~ In this Condition, the remaining OPERABLE CC heat exchanger is adequate to perform the heat removal function . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on the redundant capabilities afforded by the OPERABLE heat exchanger, and the low probability of a OBA occurring during this period .

The second Completion Time for Required Action 8 .1 establishes a limit on the maximum time allo'Ncd for any combination of Cond itions to be inoperable duri1=i9 a11y eo11ti1=i uous fa il ure to meet ti lis LOO.

The 144 hour0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months Completion Time provides a limitation time allovved in th is specified Cond ition after discovery of fai lure to moot tho LCO. Th is limit is eons idcrnd reasonable for situations in which multiple Conditions are entered conourrentl y. The 6.NQ oonneotor between 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 14 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months dictates that both Completion Times apply simultaneously, and the more restrictive must be mot.

C.1 and C.2 If the Required Actions and associated Completion Times are not met, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.7.1 REQUIREMENTS This SR is modified by a Note indicating that the isolation of the CC flow to individual components may render those components inoperable but does not affect the OPERABILITY of the CC System.

Point Beach B 3.7.7-5 Unit 1 - Amendment No. -264 Unit 2 - Amendment No. 86-

SW System B 3.7.8 BASES ACTIONS continued A.1

.. , or in accordance with the Risk Informed Completion If on SW pump is inoperable and both units are in MODES 1, 2, 3 or 4, acti n must be taken to restore the pump to OPERABLE status within 7 Time Program.

day . In this Condition, the remaining OPERABLE SW pumps assure adequate system flow capability. However, the overall reliability is reduced because a single failure could result in less than the required number of pumps to assure this flow. The ~ Completion Time is based on the redundant capabilities afforded by the remaining OPERABLE pumps, and the low probability of a OBA occurring during this time period .

Tne seeoflel Completiofl Time for Requircel Action A.1 establishes a li1iiit Ofl tne FnBx:imum time Bllowed for any cofl'!bination of Gonelitions to be iflopeFable eluFiflg afly eofltifluous failure to fl'!eet tnis LCO. Tne 14 elay Conipletiofl Time pro'o'ides 8 lifl'litation Ofl the tifl'le alloweel in this specified Condition after discovery of failu re to meet the LCO. This limit is oonsidered reasonable for situations in vvhich multiple Conditions are entereel concurrently. The~ oonneotor betvi'een 7 days and 14 days dictatls that both Completion Times apply simultaneously, anel the more restriotive must be met.

B.1 If two or three SW pumps are inoperable, action must be taken to restore at least the minimum number of pumps to OPERABLE status required to exit this Condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In this Condition, the remaining OPERABLE SW pumps are capable of providing the required system flow capability provided the requirements of the LCO are met (e.g., SW ring header continuous flowpath, non-essential SW isolation valves and the opposite Unit's containment fan cooler service water outlet valves). With four or more SW pumps inoperable, Condition G must be entered .

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on the redundant capabilities afforded by the remaining OPERABLE pumps, the probability for an additional active or passive failure, and the low probability of a OBA occurring during this time period .

C.1 and C.2 If the SW ring header continuous flowpath is interrupted, the ability of the System to provide required cooling water flow to required equipment must be verified within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time for Required Action C.1 effectively limits the allowed system configuration to alignments previously evaluated and found Point Beach B 3.7.8-4 Unit 1 - Amendment No. -?!B&-

Unit 2 - Amendment No. -24&

SW System B 3.7.8 BASES ACTIONS (continued) acceptable (Reference 4). Evaluated alignments with the continuous flowpath interrupted include a minimum required number of OPERABLE SW pumps with each OPERABLE SW pump aligned to all required portions of the SW header. Acceptable alignments must comport to the SW system analyses. Additionally, the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time provides sufficient time to accommodate transitory operations (e.g.

add itional equipment inoperabilities, operations required to realign systems and equipment, etc;) without requiring initiation of a unit shutdown . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is commensurate with the importance of maintaining the SW System in an OPERABLE

.. , or in accordance with the configuration .

Risk Informed Completion Time Program. Additionally, Required Action C.2 directs that the S ring header continuous flowpath must be restored within 7 day . Since acceptable alignments during this period may include less than five OPERABLE SW pumps, Requ ired Action B. 1 may limit operation in Condition C to less than 7 days.

With one or more ring header isolation valves incapable of being closed, the SW System will continue to be capable of providing the required cooling water flow to required equipment. However, the ability to isolate a break in the system while continu ing to provide cooling water to required equipment may be impaired.

With one or more ring header isolation valves closed , the SW System may remain capable of providing the required cooling water flow to the minimum required number of components depending on system alignment and the OPERABILITY of other SW System components .

Multiple closed ring header isolation valves could result in loss of cooling water to required equipment (e.g. closure of valves SW-2869 and SW-2870 will render two of the four containment fan coolers inoperable on each Unit). If multiple closed ring header isolation valves result in required equipment being inoperable, the Note to the ACTIONS Table requires entry into the applicable conditions and required actions for the systems made inoperable.

The 1-ey- Completion Time is acceptable based on the redundant capabilities afforded by the remaining OPERABLE equipment, and the low probability of a OBA or SW System line break occurring during this time period . Piping failures are not considered as the single failure for system functionality during an accident.

The second Completion Time for Required ActiGn C.2 establishes a limit on the mmcimum time allowed for any combination of Conditions to be in Point Beach B 3.7.8-5 Unit 1 - Amendment No. 72B&

Unit 2 - Amendment No . .z.te.

SW System B 3.7.8 BASES ACTIONS (continued) effect during any continuous failure to meet this LGO . The 14 day Conipletion Time provides a limitation on the time allo*..ved in this specified Condition after discovery of failure to meet the LCO . This limit is considered reasonable for situations in whioh multiple Conditions arc entered oonourrently . The Af!Q oonneotor between 7 days and 14 days dictat@s that both Completion Times apply simultaneously, and the more restrictive must be met.

D.1 and D.2 In the event one required automatic isolation valves in one or more non-essential-SW-load flowpath(s) is inoperable and the affected non-essential flowpath(s) is not isolated, the required redundant automatic isolation valve in the affected non-essential flowpath(s) must be verified OPERABLE within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This verification may be performed administratively.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time for Required Action D.1 provides sufficient time to accommodate transitory operations (e.g . additional equipment inoperabilities, operations required to realign systems and equipment, etc;) without requiring initiation of a unit shutdown. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is commensurate with the importance of maintaining the SW System in an OPERABLE configuration. Required Action D.1 is modified by a Note stating it is not required to be met if in Condition E.

This Note precludes entry into Condition H, when the required redundant automatic isolation valve in the affected non-essential

.. , or in accordance with the flowpath(s) is inoperable and Required Action D.1 cannot be met.

Risk Informed Completion Time Program. Additionally, the valvH(s) must be restored to OPERABLE status or the flowpath(s) iso ated with a seismically qualified isolation valve within 72 hour~ ! In this Condition, the overall reliability is reduced because a single failure could result in system configuration which could not assure adequate flow to required equipment. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on the flow capabilities afforded by the number of OPERABLE pumps, and the low probability of a OBA occurring during this time period.

The 14 day Completion Time pFovidcs a limitation OR the time allov'o'Cd ifl this specified CORditioR afteF diseoveFy of failuFe to nieet ti 1e LOO .

Tl lis li11 lit is co11sidered FeasoRablc foF situations in *.vhioh multiple ConditioRs aFc cRtcred eoReUFFCntly. The filill connector between 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 14 days dictates that both Completion Times apply simultaneously , and the more restriotive must be met.

Point Beach B 3.7.8-6 Unit 1 -Amendment No. ~

Unit 2 - Amendment No. ~

AC Sources - Operating B 3.8.1 BASES APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated OBA.

ACTIONS The AC power requirements for MODES 5 and 6 are covered in LCO 3.8.2, "AC Sources-Shutdown .

Bases Table B 3.8.1-1 provides a reference of Conditions that are applicable based on various inoperabilities.

A Note proh ibits the application of LCO 3.0.4.b to an inoperable standby emergency power source. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable standby emergency power source and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance .

A.1 and A.2 To ensure a highly reliable power source of offsite power remains available when the associated unit's X03 transformer is inoperable, Required Action A.1 requires verification that offsite power is supplying the associated unit's 4.16 kV safeguards buses from the opposite unit's X03 transformer within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and Required Action A.2 requires that the gas turbine generator be placed in operation within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months The 24 houF Completion Time associated with Required Action A.2 ~ \

.. , or in accordance with the sufficient time to start, synchronize and load the gas turbine .

Risk Informed Completion Time Program. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time associated with Required Action A.1 is sufficient to verify that the associated unit's safeguards buses continue to be energized from offsite power, since transfer to the opposite unit's X03 transformer should have occurred automatically. If auto bus transfer has not occurred , the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is sufficient to return offsite power to the associated unit's safeguards buses.

Point Beach B 3.8.1-11 Unit 1 - Amendment No. -245-Unit 2 - Amendment No . ~

AC Sources - Operating B 3.8.1 BASES ACTIONS (continued) With the required offsite circuit inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a Design Basis Accident or transient. A simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria .

.. , or in accordance with the B.1 Risk Informed Completion Require< Action B.1 applies when the associated unit's X04 transformer Time Program.

is inoper able. The inoperability of the associated unit's X04 transformer renders Dffsite power to the associated units safeguards buses o inoperab e. Aeeemfo~g te Regu latory Guide 1.93 (Ref. 5) , ~ eration may con inue in Condition B for a period that shou ld not ~ceed ~

24 hour~ ! This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded.

Because of the normally high availability of the offsite source, this level of degradation may appear to be more severe than other combinations of AC sources inoperable that involve one or more inoperable standby emergency power sources. However, two factors tend to decrease the severity of this level of degradation:

a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and

b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.

With the required offsite circuit inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a OBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria .

Point Beach B3.8.1-12 Unit 1 - Amendment No. ~

Unit 2 - Amendment No. ~

AC Sources - Operating B 3.8.1 BASES ACTIONS (continued) C.1 Required Action C.1, applies when offsite power to both safeguards buses on the same unit are inoperable (i.e., 1A05 and 1A06, or 2A05 and 2A06), or offsite power to safeguards buses 1A05 and 2A06 are inoperable. This level of degradation means that the offsite electrical power system does not have the capability to supply the minimum number of ESF systems required to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded . This condition is similar to that of Condition B, which aooording to Regulatory Guidt 1.Qd ~~* ~) . allows [§]

operation to continue for a period that should not ~xcee hours Because of the normally high availability of the offsite source, this7~vel of degradation may appear to be more severe than other combina ions of AC sources inoperable that involve one or more inoperable staroby emergency power sources. However, two factors tend to decreas1 ~ the

.. , or in accordance with the severity of this level of degradation:

Risk Informed Completion Time Program. a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and

b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.

With the required offsite circuit inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a OBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.

Condition D applies when offsite power is inoperable to one or more required 4.16 kV safeguards bus( es). The Required Actions for this Condition provide appropriate compensatory actions for each inoperable power supply, while the combination of Condition C and Condition D dictates which combinations of buses with inoperable

.. , or in accordance with the power sources are allowed for 7 days versus 24 hour~

Risk Informed Completion Time Program. Required Action D.1 is intended to provide assurance that an event coincident with a single failure of the associated standby emergency Point Beach B 3.8.1-13 Unit 1 - Amendment No. 45-Unit 2 - Amendment No . rz.8-

AC Sources - Operating B 3.8.1 BASES ACTIONS (continued) power source will not result in a complete loss of safety function of critical redundant required features. These features are powered from the redundant safeguards train.

The Completion Time for Required Action D.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. The safeguards bus has no offsite power supplying its loads; and

b. A required feature on the other train is inoperable.

If at any time during the existence of Condition D a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked .

Discovering no offsite power to one safeguards bus coincident with one or more inoperable required redundant support or supported features, or both, results in starting the Completion Times for the Required Action. Twelve hours is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to trans ients associated with shutdown.

The remaining OPERABLE safeguards bus(es)' offsite power supplies and standby emergency power sources are adequate to supply electrical power to Train A and Train B of the onsite Class 1E Distribution System . The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature . Additionally, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 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 OBA occurring during this period .

.. , or in accordance with the Risk Informed Completion Time Program . Operation ma continue in Condition D for a period that should not exceed 7 days with offsite power to one or more 4.16 kV safeguards buses inoperable. In this condition , the reliability of the offsite system is degraded , and the potential for a loss of offsite power may be increased, with attendant potential for a challenge to the unit safety systems. However, the remaining OPERABLE 4.16 kV safeguards buses supplied by offsite power and standby emergency power sources Point Beach B3.8.1-14 Unit 1 - Amendment No. r+&

Unit 2 - Amendment No. ~

To prevent a Condition resulting in a loss of function and assure safety system reliability, the COMPLETION TIME of Condition ;c Sources - Operating D.2 is modified by a note which prohibits a Completion Time B 3.8.1 extension in accordance with the Risk Informed Completion B Time Program when more than one offsite power source is

- inoperable or when one offsite power source to more than one A required Class 1E 4.16kV bus is inoperable. site Class 1E Safeguards Distribution System .

The ~ Completion Time takes into account the capacity a id capability of the remaining AC sources, a reasonable time for epairs, and the low probability of a OBA occurring during this period. ' 1 Tl 1e seco11d 60111pletio11 Tinie fof RequiFCd Action D.2 establishes a lirrlit or1tl1e111axi111u111 ti111e allovved for any eon'lbination of FCquircd AC power sources to be inoperable during any single contig1.101.1i; occurrence of failing to fficct tl9c LCO. If Condition D is cntcFCd wl9ilc ,

for instance, a standby emergency po*Ncr source is inoperable and that gtl~mdby emergency power source is subsequently returned to OPERABLE , the LCO may alFCady 19a*vc been not met for up to 7 days.

Tl9ig eould lead to a total of 14 days, since initial failure to moot tho LOO , to 1egto1 e the offgite power supply. At tl9is time , a standby emcrgcnoy power source could again becoffic inoperable , tl9e offsite power supply restored OPERABLE, and an additional 7 days (for a total of 21 days) allovved prior to complete restoration of the LCO. The 14 day Completion Time provides a limit on tho time allmvod in a speoified oondition after disoovery of failure to meet the LCO. This limit is oonsidered reasonable for situations in which Conditions D and E are cnteFCd concurrently. The "fil:!Q" connector between the 7 day and 14 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action D.1, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."

This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition D was entered.

Condition E applies when one or more standby emergency power supplies are inoperable. Condition E contains a Note which provide clarification that, for this Condition, separate Condition entry is allowed for each inoperable standby emergency power supply. This is acceptable since the Required Actions for this Condition provide appropriate compensatory actions for each inoperable power supply, while the combination of Condition E and Condition G dictates which combinations of buses with inoperable power sources are allowed for 7 days versus 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Required Action E.1 is intended to provide assurance that a loss of offsite power, during the period that a standby emergency power source is inoperable, does not result in a complete loss of safety function of Point Beach B 3.8.1-15 Unit 1 - Amendment No. -245-Unit 2 - Amendment No. -2Zfr

AC Sources - Operating B 3.8.1 BASES ACTIONS (continued) not met for up to 7 days. This could lead to a total of 14 days, since initial failure to meet the LCO, to restore the standby emergency power source. At this time, an offsite source could again become inoperable, the standby emergency power source restored OPERABLE, and an additional 7 days (for a total of 21 days) allowed prior to complete restoration of the LCO. The 14 day Completion Time provides a limit on time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions D and E are entered concurrently. The "AND" connector between the 7 day and 14 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action E.1, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed time "clock." This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition E was entered.

F.1 and F.2

[New Paragraph]

Conditions F.1 and F.2 allow 12 ursuant to LCO 3.0.6, the distribution system Actions would not be ntered even if all AC sources to it were inoperable, resulting in de-hours, or in accordance with the nergization . Therefore , the Required Action of Condition F are Risk Informed Completion Time edified by a Note to indicate that when Condition F is entered with no Program, to either restore the C power to any Class 1E 4.16 kV bus, the Conditions and Required required offsite circuit to ctions for LCO 3.8.9, "Distribution Systems - Operating" must be OPERABLE or restore the mediately entered . This allows Condition F to provide requirements required standby emergency r the loss of one offsite power source to one or more Class 1E power source to OPERABLE, .16 kV bus(es) and one required standby emergency power source, ithout regard to whether a train is de-energized . LCO 3.8.9 provides respectively. To prevent a ppropriate restrictions for a de-energized Class 1E 4.16 kV bus.

Condition resulting in a loss of function and assure safety system reliability, the COMPLETION TIME of Conditions F.1 and F.2 is equ ired Action G.1 applies to each unit in MODE 1, 2, 3 or 4, when modified by a note which prohibits tandby emergency power to both safeguards buses on the same unit 3 Completion Time extension in re inoperable (i.e., 1A05/1 B03 and 1A06/1 B04, or 2A05/2B03 and accordance with the Risk A06/2B04), or standby emergency power to safeguards buses

. . A05/1 B03 and 2A06/2B04 are inoperable. Thus, with an assumed Informed Completion Time ss of offsite electrical power, insufficient standby emergency power Program when more than one ources are available to power the minimum required ESF functions.

required offsite power source is inoperable or when one offsite ince the offsite electrical power system is the only source of AC power power source to more than one r this level of degradation , the risk associated with continued Class 1E 4.16kV bus safeguard peration for a very short time could be less than that associated with n immediate controlled shutdown (the immediate shutdown could buses is inoperable.

Point Beach B3.8.1-18 Unit 1 - Amendment No. ~

Unit 2 - Amendment No. ~

DC Sources-Operating B 3.8.4 BASES ACTIONS The ACTIONS are modified by a Note which ensures appropriate remedial aGtions are taken if a DC bus becomes de-energized.

Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if a DC electrical power subsystem were inoperable, resulting in de-energization of a DC bus. Therefore, the Actions are modified by a Note to indicate that when DC bus is de-energized, the Conditions and Required Actions for LCO 3.8.9, "Distribution Systems-Operating," must be entered. This allows Condition A to provide requirements for the inoperability of a battery or charger, without regard to whether a bus is de-energized. LCO 3.8.9 provides the appropriate restrictions for a de-energized bus.

A.1 Condition A represents one DC subsystem with a loss of ability to completely respond to an event, and a potential loss of ability to remain energized during normal operation . It is, therefore, imperative that the operator's attention focus on stabilizing the unit, minimizing the potential

.. , or in accordance with the for any further loss of DC power.

Risk Informed Completion Time Program. If one of the required DC electrical power subsystems is inoper. ~ ble (e .g. , inoperable battery, inoperable battery charger(s), or inoperable battery charger and associated inoperable battery), the remainir g DC electrical power subsystems have the capacity to support a safe shutdown and to mitigate an accident condition . Since a subsequent worst case single failure could result in the loss of an additional 125 VDC electrical power subsystem with the potential fo r loss Df ESF functions, continued power operation should not exceed 2 houri ~ The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is based on Regulatory Guide 1.93 (Ref. 5)

-BM reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power subsystem and , if the DC electrical power subsystem is not restored to OPERABLE status, to prepare to effect an orderly and safe unit shutdown .

B.1 and B.2 If the inoperable DC electrical power subsystem cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems . The Completion Time to bring the unit to MODE 5 is consistent with the time required in Regulatory Guide 1.93 (Ref. 5) .

Point Beach B 3.8.4-4 Unit 1 - Amendment No. 7&1-Unit 2 - Amendment No . .ZOO

v t e Letter Sequence Response to RAI
EPID:L-2022-LLA-0074, TSTF-505 (Approved, Closed)
Initiation Request, Request, Request Acceptance, Acceptance Supplement Administration Questions 20 December 2022 31 January 2023 Answers 21 February 2023 Results Approval, Approval Other: ML23039A002
MONTHYEAR2022-07-15 [Table View]

ML23011A280

Text

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