ML19224B705

Response to Request for Additional Information: License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended...

ML19224B705
Person / Time
Site:	Limerick
Issue date:	08/12/2019
From:	David Gudger Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML19224B705 (142)

Text

200 Exelon Way Kennett Square, PA 19348 www.exeloncorp.com 10 CFR 50.90 August 12, 2019 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 ATTN: Document Control Desk Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 NRC Docket Nos. 50-352 and 50-353

Subject:

Response to Request for Additional Information License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b."

References:

1. Letter from J. Barstow (Exelon Generation Company, LLC) to U.S.

Nuclear Regulatory Commission, License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b'," dated December 13, 2018 (ADAMS Accession No. ML18347B366).

2. Letter from D. Helker (Exelon Generation Company, LLC) to U.S. Nuclear Regulatory Commission, Supplement to License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b," dated February 14, 2019 (ADAMS Accession No. ML19045A011).

3. Electronic mail message from V. Sreenivas, U.S. Nuclear Regulatory Commission, to G. Stewart, Exelon Generation Company, LLC, "Limerick-Request for Additional Information: Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Completion Times -

RITSTF Initiative 4b (EPID L-2018-LLA-0567)," dated July 10, 2019 (ADAMS Accession No. ML19192A031).

By letter dated December 13, 2018 (Reference 1), as supplemented by letter dated February 14, 2019 (Reference 2), Exelon Generation Company, LLC (Exelon) requested an amendment to the Renewed Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (Limerick), Units 1 and 2, respectively.

U.S. Nuclear Regulatory Commission Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 August 12, 2019 Page 2 The proposed amendment would modify Technical Specifications (TS) requirements to permit the use of risk-informed completion times (RICTs) in accordance with the Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF [Risk-Informed TSTF] Initiative 4b (Agencywide Documents Access and Management System (ADAMS) Accession No. ML18183A493).

During June 17, 2019 to June 21, 2019 the U.S. Nuclear Regulatory Commission (NRC) staff conducted an audit at Exelons offices in Kennett Square, Pennsylvania to support development of its safety evaluation. Upon completion of the audit, the NRC staff determined that additional information is needed to complete its review of the LAR.

A draft request for additional information (RAI) was provided to G. Stewart (Exelon) by electronic email dated July 2, 2019. A conference call was subsequently held with the NRC on July 10, 2019 to provide clarification of the draft RAI questions. The formal RAI was issued by electronic email to G. Stewart (Exelon) on July 10, 2019 (Reference 3).

As noted in Reference 3, response to the RAI questions is required by August 12, 2019 except for APLA RAI-02, RAI-03 and RAI-08. Due to the need to perform sensitivity analyses and other additional studies, response to these three RAI questions is required by August 30, 2019. to this letter provides a restatement of the NRC questions (except APLA RAI-02, RAI-03 and RAI-08) followed by our responses. Attachment 2 provides a revised set of TS markups which replaces in its entirety the TS markups provided in Reference 1. provides information supporting the redundancy and diversity of the instrumentation included in the license amendment request. Enclosure 1 provides a revised Table E1-1 which replaces in its entirety Table E1-1 provided in Reference 1.

Exelon has reviewed the information supporting a finding of no significant hazards consideration, and the environmental consideration, that were previously provided to the NRC in Attachment 1 of the Reference 1 letter. Exelon has concluded that the information provided in this response does not affect the bases for concluding that the proposed license amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92. In addition, Exelon has concluded that the information in this response does not affect the bases for concluding that neither an environmental impact statement nor an environmental assessment needs to be prepared in connection with the proposed amendment.

In accordance with 10 CFR 50.91, "Notice for public comment; State consultation,"

paragraph (b), Exelon is notifying the Commonwealth of Pennsylvania of this supplement to the application for license amendment by transmitting a copy of this letter and its attachment to the designated State Official.

U.S. Nuclear Regulatory Commission Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 August 12, 2019 Page 3 This letter contains no regulatory commitments.

If you should have any questions regarding this submittal, please contact Glenn Stewart at 610-765-5529.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 12th day of August 2019.

Respectfully, J {M.-.;J f ~J~

David T. Gudger Sr. Manager, Licensing Exelon Generation Company, LLC Attachments:

1. License Amendment Request - Response to Request for Additional Information

2. Proposed Technical Specifications Changes (Revised Markups)

3. Information Supporting Instrumentation Redundancy and Diversity

Enclosure:

1. List of Revised Required Actions to Corresponding PRA Functions cc: USNRC Region I, Regional Administrator USNRC Project Manager, Limerick USNRC Senior Resident Inspector, Limerick Director, Bureau of Radiation Protection - Pennsylvania Department of Environmental Protection

ATTACHMENT 1 License Amendment Request Limerick Generating Station, Units 1 and 2 NRC Docket Nos. 50-352 and 50-353 Response to Request for Additional Information License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b."

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 1 of 42 Docket Nos. 50-352 and 50-353 By letter dated December 13, 2018 (Reference 1), as supplemented by letter dated February 14, 2019 (Reference 2), Exelon Generation Company, LLC (Exelon) requested an amendment to the Renewed Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (Limerick/LGS), Units 1 and 2, respectively.

The proposed amendment would modify Technical Specifications (TS) requirements to permit the use of risk-informed completion times (RICTs) in accordance with the Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF [Risk-Informed TSTF] Initiative 4b (Agencywide Documents Access and Management System (ADAMS) Accession No. ML18183A493).

During June 17, 2019 to June 21, 2019 the U.S. Nuclear Regulatory Commission (NRC) staff conducted an audit at Exelons offices in Kennett Square, Pennsylvania to support development of its safety evaluation. Upon completion of the audit, the NRC staff determined that additional information is needed to complete its review of the LAR.

A draft request for additional information (RAI) was provided to G. Stewart (Exelon) by electronic email dated July 2, 2019. A conference call was subsequently held with the NRC on July 10, 2019 to provide clarification of the draft RAI questions. The formal RAI was issued by electronic email to G. Stewart (Exelon) on July 10, 2019 (Reference 3).

As noted in Reference 3, response to the RAI questions is required by August 12, 2019 except for APLA RAI-02, RAI-03 and RAI-08. Due to the need to perform sensitivity analyses and other additional studies, response to these three RAI questions is required by August 30, 2019.

A restatement of the NRC questions (except APLA RAI-02, RAI-03 and RAI-08) followed by our responses is provided below.

A. PROBABILISTIC RISK ANALYSIS (PRA) LICENSING BRANCH A (APLA)

APLA RAI Key Assumptions and Sources of Uncertainty Regulatory Position C of Regulatory Guide (RG) 1.174, Revision 3, (Agencywide Documents Access and Management System (ADAMS) Accession Number (No.) ML17317A256) states:

In risk-informed decisionmaking, licensing basis changes are expected to meet a set of key principles In implementing these principles, the staff expects the following Uncertainty receives appropriate consideration in the analyses and interpretation of findings NUREG-1855 provides acceptable guidance for the treatment of uncertainties in risk-informed decisionmaking NUREG-1855, Revision 1 (ADAMS Accession No. ML17062A466) provides guidance on screening sources of uncertainty and determining those that are key sources of uncertainty for the application. NUREG-1855, Revision 1 identifies EPRI Topical Report (TR) 1016737 and EPRI TR 1026511 as providing additional guidance for identifying and characterizing key sources of uncertainty.

Section 2.3.4 of Nuclear Energy Institute (NEI) 06-09, Revision 0-A (ADAMS Accession No. ML12286A322), states that PRA modeling uncertainties be considered in application of the PRA base model results to the risk-informed completion time (RICT) program. The NRC Safety Evaluation (SE) for NEI 06-09, Revision 0, states that this consideration is consistent with Section 2.3.5 of RG 1.177, Revision 1 (ADAMS Accession No. ML100910008). NEI 06-09,

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 2 of 42 Docket Nos. 50-352 and 50-353 Revision 0-A, further states that sensitivity studies should be performed on the base model prior to initial implementation of the RICT program on uncertainties which could potentially impact the results of a RICT calculation. These sensitivity studies should be used to develop appropriate compensatory Risk Management Actions (RMAs) such as highlighting risk significant operator actions, confirming availability and operability of important standby equipment, and assessing the presence of severe or unusual environmental conditions. of the License Amendment Request (LAR) (ADAMS Accession No. ML18347B366) states that the uncertainty analysis for the internal events PRA was performed based on guidance from NUREG-1855, Revision 1, and EPRI TR 1016737. The LAR indicates that plant--specific key assumptions and modeling uncertainties from the internal events PRA documentation were considered, as well as generic sources of uncertainty from EPRI TR 1016737. However, the LAR does not discuss how the sources of modeling uncertainty were identified for the fire PRA or for the Level 2 (e.g., LERF) PRA, nor does it explicitly explain whether both plant-specific and generic modeling sources of uncertainty were considered for the fire and Level 2 PRA models. NRC notes that generic modelling uncertainties for fire and Level 2 PRAs are identified in EPRI TR 1026511.

Tables E9-1, E9-2, and E9-3 of Enclosure 9 of the LAR provide, respectively, 13 sources of uncertainty related to the internal events PRA (none of which are related to internal flooding),

three sources of uncertainty related to translation of the PRA models to the Real-Time Risk (RTR) model, and 16 sources of uncertainty related to the fire PRA. Most of the identified sources of uncertainty were dispositioned as not being key uncertainties because they do not impact or have only a minor impact on the RICT calculations, or because the PRA uses consensus modeling approaches, or because the assumption was determined to not be a source of uncertainty. The LAR does not describe the assessment process used to determine that the assumptions and sources of uncertainty included in these tables are those that are potentially key to the RICT application.

Considering the observations above, address the following:

a. Describe, separately for the internal events, internal flooding and the fire PRAs, the process used to identify and evaluate key assumptions and sources of model uncertainty. Address the following in the response:

i. Discuss how a comprehensive list of plant-specific and generic industry key assumptions and sources of uncertainty were identified as a starting point for this evaluation.

Response

The PRA documentation identifies plant specific assumptions that may be key to the calculated risk. The list of potential sources of model uncertainty for internal events and internal flooding was examined based on the guidance in EPRI 1016737. This included the identification of some plant-specific sources of uncertainty that were not part of the EPRI list. Subsequent to that analysis, a detailed assessment of the generic industry potential sources of Level 2 model uncertainty from Appendix E of EPRI 1026511 was also performed. This did not identify any additional potential sources of uncertainty for the applications other than those summarized in Table E9-1 of the LAR.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 3 of 42 Docket Nos. 50-352 and 50-353 The initial assessment for the fire PRA in the LAR for Limerick was based on the 16 tasks from NUREG/CR-6850. Subsequent to that analysis, a detailed assessment of the generic industry potential sources of fire PRA model uncertainty from Appendix B of EPRI 1026511 was also performed. This did not identify any additional potential sources of uncertainty for the applications other than those summarized by the 16 tasks from NUREG/CR-6850 in Enclosure 9 of the LAR.

ii. Explain how the comprehensive list of key assumptions and sources of uncertainty sources was screened to a list of uncertainties that were specifically evaluated for their impact on the RICT application.

Response

The list of potentially important assumptions and related sources of model uncertainty as noted in the response to Part i above was screened based on a review of each topic and the manner in which the PRA incorporates the applicable guidance. The type of approach utilized in implementing each topic in the PRA (e.g., use of a consensus approach, or other applicable guidance), and the level of detail included in the PRA are means used to determine and screen potential impacts on the application. The unscreened assumptions and sources of model uncertainty represent those that may be key to the application.

iii. Explain what criteria or what additional analysis was used to evaluate the impact of the key assumptions and sources of uncertainty on the RICT application.

Response

The criteria used to evaluate the key assumptions and sources of uncertainty include an assessment to determine whether each potential item on the screened list noted in response to Part ii above would challenge the acceptance guidelines for RICT implementation. It is expected that reasonable changes to the assumptions associated with potential sources of uncertainty could lead to a shift in the calculated delta risk for the RICT application but would tend to not totally shift the dominant contributors for the configurations. In the case of RICT, appropriate compensatory measures to address the dominant contributors for the configuration will be in place prior to the RMAT being exceeded and for the remaining duration of the RICT configuration to help to minimize the risk. RMAs will be developed as described in Enclosure 12 of the LAR, consistent with the guidance in NEI 06-09, using insights from the PRA models and other good practices (e.g., minimizing durations of maintenance activities and minimizing work on redundant trains of equipment).

Also note that specific sensitivities to potential key sources of uncertainty are also being performed and the results of those sensitivities will be reported in the responses to RAIs APLA-02, -03, and -08. If these additional sensitivity cases identify additional RMAs, these will be incorporated into the RICT program.

iv. Describe how the evaluation process aligns with guidance in NUREG-1855, Revision 1, or other NRC-accepted processes.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 4 of 42 Docket Nos. 50-352 and 50-353

Response

The evaluation process described above aligns with NUREG-1855, Revision 1 with respect to Stage E - Assessing Model Uncertainty as described below.

• Step E-1.1 (Identification of Sources of Model Uncertainty and Related Assumptions): Tables A-1 and A-2 of EPRI 1016737 were used to identify potential sources of model uncertainty from the internal events and internal flooding PRA models. Appendix B and Appendix E of EPRI 1026511 were used to identify potential sources of model uncertainty in the fire PRA and Level 2 PRA model, respectively. Unique plant-specific issues were also considered in the identification process for the PRA models.

• Step E-1.2 (Identification of Relevant Sources of Model Uncertainty and Related Assumptions): This step allows for screening of potential sources of model uncertainty based on the parts of the models used for the application. Since the Risk-Informed Completion Time evaluations involve complete model re-quantification for each case analyzed, no specific potential sources of uncertainty were screened out for this application.

• Step E-1.3 (Characterization of Sources of Model Uncertainty and Related Assumptions): Per the guidance in NUREG-1855 and the associated EPRI reports, the characterization process involves identifying: 1) the part of the PRA model affected, 2) the modeling approach or assumptions utilized in the model, 3) the impact on the PRA model, and 4) representation of conservative bias (if applicable). These considerations were included in the evaluation of the potential sources of model uncertainty for Limerick.

• Step E-1.4 (Qualitative Screening of Sources of Model Uncertainty and Related Assumptions): This step allows for screening out potential sources of model uncertainty by referencing consensus model approaches. The evaluation process for Limerick included identifying the approach utilized (e.g., consensus approach or other applicable guidance) and using those considerations as the means to qualitatively screen potential impacts on the application.

• Step E-1.5 (Identification and Characterization of Relevant Sources of Model Uncertainty and Related Assumptions Associated with Model Changes): The implementation of the RICT program utilizes the base PRA models with some specific optimization to improve quantification speed. The FPIE PRA model logic structure is not structurally altered for optimization. For the Fire PRA model, where there is a group of fire initiators that have the exact same event impact, the group of initiators may be quantified using a single representative initiator for the group.

In these cases, the representative event frequency is set to the maximum initiating event frequency for the group and then reset to the sum of the group frequency to ensure that the CDF/LERF value for the configuration, and therefore the RICT calculation, is not under-estimated for the truncation value utilized. As described in the response to RAI APLA-04, the results for optimized portions of the Real Time Risk will be reviewed to ensure a logically equivalent result is achieved in comparison to the Model of Record. As such, no new sources of model uncertainty have been introduced for the application.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 5 of 42 Docket Nos. 50-352 and 50-353

• Step E-2 (Identification of Key Sources of Model Uncertainty and Related Assumptions): As described in NUREG-1855, only the relevant sources of uncertainties and related assumptions with the potential to challenge the applications acceptance guidelines are considered key. Also, per NUREG-1855, if any sources of uncertainty do challenge the acceptance guidelines, then appropriate compensatory measures or performance monitoring should be identified to help minimize the risk. In the case of RICT, appropriate compensatory measures will be in place prior to the RMAT being exceeded and for the remaining duration of the RICT configuration. RMAs will be developed as described in Enclosure 12 of the LAR using insights from the PRA models and other good practices (e.g., minimizing durations of maintenance activities and minimizing work on redundant trains of equipment). Additionally, Enclosure 11 of the LAR describes the performance monitoring that will be associated with the RICT program at Limerick. As such, the overall RICT program implementation is consistent with Step E-2 of NUREG-1855.

b. In accordance with the process described in NUREG-1855, Revision 1, describe any additional sources of internal events, internal flooding, or fire PRA model uncertainty and related assumptions relevant to the application that were not provided in LAR Enclosure 9 and describe their impact on the application results.

Response

No additional plant specific or generic key assumptions or uncertainties were identified. Per the process described in NUREG-1855, Revision 1 and EPRI 1016737 and1026511, the key assumptions and uncertainties were summarized in Enclosure 9 of the LAR. As discussed above, RMAs will be developed when appropriate using insights from the PRA model results specific to the configuration. This will help to minimize the risk and offset any potential issues associated with specific sources of uncertainty for the configuration.

c. For any additional sources of model uncertainty and related assumptions identified in part b:

i. Provide qualitative or quantitative justification that these uncertainties and assumptions do not challenge the RG 1.174 risk acceptance guidelines.

ii. Justify that these key uncertainties and assumptions have no impact on the RICT calculations or, if determined to have a significant impact, consistent with the guidance in NEI 06-09-A, discuss the RMAs for each key uncertainty and assumption that will be implemented to minimize their potential adverse impact.

Response

No additional plant specific or generic key assumptions or uncertainties were identified. The disposition of most of the candidate sources as not being key involved use of consensus or generally accepted approaches or noting that a slight conservative bias slant was used in model development. Although conservative bias approaches may lead to masking delta risk increases in some cases, these approaches should generally not contribute significantly to the base risk values (e.g., to meet Capability Category II for FSS-C1 of the PRA standard, the lack of two-point fire model treatment for certain scenarios is confirmed to contribute no

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 6 of 42 Docket Nos. 50-352 and 50-353 more than 0.5% of the base fire risk). In a bounding case, the calculated delta risk that is potentially masked would be no more than the base case value (i.e., it goes to zero if not masked and goes to the base value when the potentially masked component is taken out of service). Therefore, the calculated changes to RICT would be minimal as shown in the illustrative example below which assumes a total masked contribution of 5%.

• Assume total base CDF from all contributors is 1.0E-5.

• Assume masked contribution is up to 5% of that total: 0.05

• 1.0E-5 = 5.0E-7

• For various RICT times the calculated required increase in CDF (i.e., 1E-5/(# Days/365)) and potential impact from masking (at 5% of base CDF) is shown below.

Calculated Delta-CDF Adjusted RICT (with Ratio to RICT 5E-7 masked delta Default risk) Calculation 5.0 Days 7.30E-4 4.997 Days 99.9%

10.0 Days 3.65E-4 9.986 Days 99.9%

20.0 Days 1.83E-4 19.95 Days 99.7%

30.0 Days 1.22E-4 29.88 Days 99.6%

APLA RAI Real-Time Risk Model Regulatory Position 2.3.3 of RG 1.174, Revision 3, states that the level of detail in the PRA should be sufficient to model the impact of the proposed licensing basis change. The characterization of the problem should include establishing a cause-effect relationship to identify portions of the PRA affected by the issue being evaluated. Full-scale applications of the PRA should reflect this cause-effect relationship in a quantification of the impact of the proposed licensing basis change on the PRA elements.

Section 4.2 of NEI 06-09, Revision 0-A, describes attributes of the configuration risk management tool (CRM). A few of these attributes are listed below:

• Initiating events accurately model external conditions and effects of out-of-service equipment.

• Model translation from the PRA to a separate CRM tool is appropriate; CRM fault trees are traceable to the PRA. Appropriate benchmarking of the CRM tool against the PRA model shall be performed to demonstrate consistency.

• Each CRM application tool is verified to adequately reflect the as-built, as-operated plant, including risk contributors which vary by time of year or time in fuel cycle or otherwise demonstrated to be conservative or bounding.

• Application specific risk important uncertainties contained in the CRM model (that are identified via PRA model to CRM took benchmarking) are identified and evaluated prior to use of the CRM tool for RMTS applications.

• CRM application tools and software are accepted and maintained by and appropriate quality program.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 7 of 42 Docket Nos. 50-352 and 50-353

• The CRM tool shall be maintained and updated in accordance with approved station procedures to ensure it accurately reflects the as-built, as-operated plant. of the LAR describes the attributes of the RTR model, Limericks CRM tool, for use in RICT calculations. The LAR explains that the internal flooding PRA model is integrated into the internal events PRA model, but the fire PRA model is maintained as a separate model. The LAR also describes several changes made to the internal events and fire PRA models to support calculation of configuration-specific risk and mentions approaches for ensuring the fidelity of the RTR to the PRAs including RTR maintenance, documentation of changes, and testing. With regards to development and application of the RTR model, provide the following:

a. Explain how any changes in success criteria based on seasonal variations are accounted for in the RTR model for use in RICT calculations.

Response

The Diesel Enclosure Ventilation System is a safety related system that exhausts air from each of four Diesel Generator Cells in the Diesel Generator Enclosure in each unit.

Each Diesel Generator Cell contains two safety related Diesel Generator Ventilation Air Exhaust Fans. The exhaust fans are each 50% capacity when the ambient (outside) temperature exceeds 75°F. Below 75°F, only one fan is required for ventilation of each cell. The Limerick RTR model assumes that the outside temperature is above 75 degrees by default and operators can indicate when outside temperature is below 75 degrees.

The PRA models the need to utilize the Spray Pond winter bypass valves to allow water ingress below the surface of the spray pond which would eventually break up any ice layer that exists on the surface of the pond so that the spray network could be used. The RTR model will include a way for operators to indicate when the outside temperature is below 32 degrees and the possibility of ice formation on the spray pond surface exists.

Operations verifies that the schedule used for the RICT calculation appropriately reflects these conditions in accordance with Exelon configuration risk management procedures.

This is consistent with our current (a)(4) process.

b. Confirm that out-of-service equipment will be properly reflected in the RTR Model initiating event models as well as in the system response models.

Response

The Limerick PRA Model utilizes system initiator event fault trees, so the associated equipment unavailabilities that contribute to initiating events are captured explicitly in these system initiator fault trees.

c. Describe the process that will be used to maintain the accuracy of any pre-solved cutsets with changes in plant configuration.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 8 of 42 Docket Nos. 50-352 and 50-353

Response

Full PRA model quantifications will be used for each configuration. Pre-solved cutsets are only used for configurations that are identical to previously experienced configurations. For configurations without available configuration-specific cutsets the model will be quantified to produce cutsets for the specific RICT configuration. In accordance with Exelon Risk Management procedures, when there are any changes in the underlying PRA model of record, the PRA Results database in Paragon will be updated to repopulate the configuration-specific cutsets.

d. Describe the benchmarking activities performed to confirm consistency of the RTR model to base PRA model results, including periodicity of RTR updates compared to the base PRA model updates.

Response

Every PRA model of record (MOR) Update results in an update to the RTR model in accordance with the Exelon Risk Management FPIE update procedure and a pending update to the Fire PRA Update procedure. The RTR model documentation includes changes made to the MOR model files to work with the RTR model software (e.g.,

quantification settings) along with verification that results are consistent between the RTR and PRA zero maintenance results. The checks completed for this verification process are detailed in the Risk Management procedures. This is consistent with the current Exelon 10CFR50.65 (a)(4) process. In addition, the RTR update for the MOR includes quantifying the RTR model for representative maintenance configurations and examining the results for appropriateness.

APLA RAI Identification of Compensatory Measures and RMAs The NRC SE for NEI 06-09, Revision 0-A, states that the LAR will describe the process to identify and provide compensatory measures and RMAs during extended CTs. LAR 2 identifies three kinds of RMAs (i.e., actions to provide increased risk awareness and control, reduction of the duration of maintenance activities, and reduction of the magnitude of risk increase). LAR Enclosure 12 also provides examples of RMAs for an unavailable diesel generator, battery charger, RHR pump, and for loss of off-site power. LAR Enclosure 12 does not describe what criteria or insights (e.g., important fire areas, important operator actions) are used to determine what RMAs to apply in specific instances. Therefore:

a. Describe the criteria and insights (e.g., important fire areas, important operator actions) that are used to determine the compensatory measures and RMAs to apply in specific instances.

Response

Risk Management Actions (RMAs) are compensatory measures to reduce risk.

Determination of RMAs involves the use of both qualitative and quantitative considerations for the specific plant configuration and the practical means available to manage risk. The scope and number of RMAs developed and implemented are reached in a graded manner.

Exelon Risk Management procedures contain guidance for development of RMAs in support of the RICT program. Development of RMAs considers those developed for other

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 9 of 42 Docket Nos. 50-352 and 50-353 processes, such as the RMAs developed under the 10CFR 50.65(a)(4) program and the protected equipment program. Additionally, Common Cause RMAs are developed to address the potential impact of common cause failures.

RMAs are identified based on the configuration-specific risk. There are three categories of RICT RMAs:

1) Actions to increase risk awareness and control, such as briefing of crews on risk important operator actions and procedures.

2) Actions to reduce the duration of maintenance activities, such as performing activities around the clock.

3) Actions to minimize the magnitude of the risk increase, such as protecting risk important equipment or minimizing fire risk in risk important rooms.

General RMAs are developed for input into the site-specific RICT system guidelines. These guidelines are developed using a graded approach. Consideration is given for system functionality. These RMAs include:

• Consideration of rescheduling maintenance to reduce risk

• Discussion of RICT in pre-job briefs

• Consideration of proactive return-to-service of other equipment

• Efficient execution of maintenance.

In addition to the RMAs developed qualitatively for the system guidelines, RMAs are developed based on the Real-Time Risk tool to identify configuration-specific RMA candidates to manage the risk associated with internal events, internal flooding, and fire events. These actions include:

• Identification of important equipment or trains for protection

• Identification of important Operator Actions for briefings

• Identification of key fire initiators and fire zones for RMAs in accordance with the site Fire RMA process

• Identification of dominant initiating events and actions to minimize potential for initiators

• Consideration of insights from PRA model cutsets, through comparison of importances.

Common cause RMAs are also developed to ensure availability of redundant SSCs, to ensure availability of diverse or alternate systems, to reduce the likelihood of initiating events that require operation of the out-of-service components, and to prepare plant personnel to respond to additional failures. Common cause RMAs are developed by considering the impact of loss of function for the affected SSCs.

Examples of common cause RMAs include:

• Performance of non-intrusive inspections on alternate trains

• Confidence runs performed for standby SSCs

• Increased monitoring for running components

• Expansion of monitoring for running components

• Deferring maintenance and testing activities that could generate an initiating event which would require operation of potentially affected SSCs

• Readiness of operators and maintenance to respond to additional failures

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 10 of 42 Docket Nos. 50-352 and 50-353

• Shift briefs or standing orders which focus on initiating event response or loss of potentially affected SSCs.

b. Explain how RMAs are identified for emergent conditions in which the extent of condition evaluation for inoperable SSCs is not complete prior to exceeding the Completion Time to account for the increased possibility of a common cause failure (CCF). Include explanation of if and how these RMAs are different from other RMAs.

Response

Common cause RMAs are additional RMAs focused on ensuring availability of redundant components, ensuring availability of diverse or alternate systems, reducing the likelihood of initiating events to that require operation of the out-of-service components, and readiness of plant personnel to respond to additional failures.

In accordance with Exelon procedures, for emergent conditions where the extent of condition is not completed prior to entering into the Risk Management Action Times or the extent of condition cannot rule out the potential for common cause failure, common cause RMAs are expected to be implemented to mitigate common cause failure potential and impact. These can include the pre-identified RMAs included in the system guidelines as discussed in the response to APLA RAI-05, Item a., as well as additional common cause RMAs for the specific configuration. Appropriate RMAs, including both regular and common cause considerations, are developed for the specific configuration using the considerations specified in the response to APLA RAI-05, Item a.

APLA RAI Evaluation of Common Cause Failures for Planned Maintenance NEI 06-09, Revision 0-A, states that no common cause failure (CCF) adjustment is required for planned maintenance. The NRC SE for NEI 06-09, Revision 0, is based on conformance with RG 1.177, Revision 1. Specifically, SE Section 2.2 states that, specific methods and guidelines acceptable to the NRC staff are [] outlined in RG 1.177 for assessing risk-informed TS changes. SE Section 3.2 further states that compliance with the guidance of RG 1.174, Revision 1, and RG 1.177, Revision 1, is achieved by evaluation using a comprehensive risk analysis, which assesses the configuration-specific risk by including contributions from human errors and common cause failures.

The guidance in RG 1.177, Revision 1, Section 2.3.3.1, states that, CCF modeling of components is not only dependent on the number of remaining in-service components but is also dependent on the reason components were removed from service (i.e. whether for preventative or corrective maintenance). In relation to CCF for preventive maintenance, the guidance in RG 1.177, Appendix A, Section A-1.3.1.1, states:

If the component is down because it is being brought down for maintenance, the CCF contributions involving the component should be modified to remove the component and to only include failures of the remaining components (also see Regulatory Position 2.3.1 of Regulatory Guide 1.177).

According to RG 1.177, Revision 1, if a component from a CCF group of three or more components is declared inoperable, the CCF of the remaining components should be modified

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 11 of 42 Docket Nos. 50-352 and 50-353 to reflect the reduced number of available components in order to properly model the as-operated plant.

a. Explain how CCFs are included in the PRA model (e.g., with all combinations in the logic models as different basic events or with identification of multiple basic events in the cut sets).

Response

In the LGS PRA models, CCF event probabilities are modeled and quantified using the alpha factor method described in NUREG/CR-5485 (Reference APLA RAI-06.1), with alpha factors from, or based on, updated CCF parameters on the associated NRC web site (Reference APLA RAI-06.2). Common cause basic events are explicitly modeled in the one-top fault tree, with each specific combination of events modeled in conjunction with the independent failure basic event. For example, consider a group consisting of components A, B, C, and D where failure of all four components is necessary to fail the PRA mitigation function. Failure of component A is modeled as an OR gate of the independent failure event for A, along with seven additional common cause basic events for combinations of AB, AC, AD, ABC, ABD, ACD, and ABCD.

b. Explain how the quantification and/or models will be changed when, for example, one train of a 3x100 percent train system is removed for preventative maintenance and describe how the treatment of CCF meets the guidance in RG 1.177, Revision 1, or meets the intent of this guidance when quantifying a RICT.

Response

The common cause events are not adjusted during quantification for planned maintenance.

Adjustments to the CCF grouping or CCF probabilities are not necessary when a component is taken out-of-service for preventative maintenance (PM). The component is not out-of-service for reasons subject to a potential common cause failure, and so the in-service components are not subject to increases in common cause probabilities.

The net failure probability for the in-service components includes the CCF contribution of the out-of-service component. This CCF contribution from the out-of-service component is conservatively retained two ways:

1. The independent failure event used in the model includes both the independent and dependent failure probabilities.

2. The CCF event probabilities that include the out-of-service component are retained.

As described in RG 1.177, Section A-1.3.2.2, the CCF term should be treated differently when a component is taken down for preventive maintenance than as described for failure of a component. For PMs, the common cause factor is changed so that the model represents the unavailability of the remaining component. In the example provided in the RG for a 2-train system, the CCF event can be set to zero for PMs. This is done so that the model represents the unavailability of the remaining component, and not the common cause

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 12 of 42 Docket Nos. 50-352 and 50-353 multiplier. The Exelon approach is conservative in that for a 2-train system, the CCF event is retained for the component removed from service. Likewise, for systems with three or more trains, the CCF events that are related to the out-of-service component are retained.

This is the same as the Calvert Cliffs approach described in response to RAI 21 in reference APLA RAI-06.3.

References:

APLA RAI-06.1 NUREG/CR-5485, Guidelines on Modeling Common-Cause Failures in Probabilistic Risk Assessment, Idaho National Engineering and Environmental Laboratory, June 1998.

APLA RAI-06.2 https://nrcoe.inl.gov/resultsdb/ParamEstSpar/

APLA RAI-06.3 Letter from James Barstow (Exelon Generation Company, LLC) to U.S.

Nuclear Regulatory Commission Response to Request for Additional Information License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 1, "Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b." dated June 21, 2018 (ADAMS Accession No. ML18172A145).

APLA RAI Evaluation of Common Cause Failure for Emergent Conditions TS Administrative Section constraint d states:

For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the ACTION allowed outage 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.

Regarding option 1 of constraint d, provide the following:

a. Describe and justify how the numerical adjustment for increased possibility of CCF will be performed, or

Response

Numerical adjustment of CCF events will not typically be performed for a RICT calculation.

The proceduralized process is to complete an extent of condition assessment that precludes the possibility of CCF. If CCF cannot be ruled out, then risk management actions will be put

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 13 of 42 Docket Nos. 50-352 and 50-353 in place to mitigate the potential for common cause. See the response to APLA RAI-05 for the process of identifying common cause RMAs.

b. Confirm that numerically accounting for the increased possibility of CCF in the RICT calculation will be performed in accordance with RG 1.177, Revision 1.

Response

As noted in the response to Part a. above, CCF probabilities will normally not be adjusted for emergent failures. If a numeric adjustment is performed, the RICT calculation will be adjusted to numerically account for the increased possibility of CCF in accordance with RG 1.177, Revision 1, as specified in Section A-1.3.2.1 of Appendix A of the RG. Specifically, when a component fails, the CCF probability for the remaining redundant components will be increased to represent the conditional failure probability due to CCF of these components in order to account for the possibility the first failure was caused by a common cause mechanism.

APLA RAI PRA Modeling - Other Systems The NRC SE to NEI 06-09, Revision 0, specifies that the LAR is to provide a comparison of the TS functions to the PRA modeled functions and that sufficient justification is to be provided to show that the scope of the PRA model is consistent with the licensing basis assumptions.

Additionally, Item 11 in Section 2.3 of TSTF-505, Revision 2, states:

The traveler will not modify Required Actions for systems that do not affect core damage frequency (CDF) or large early release frequency (LERF) or for which a RICT cannot be quantitatively determined.

Address the following:

a. For LCO 3.6.2.2.a (One suppression pool spray loop inoperable), LAR Table E1-1 states that suppression pool spray is not modeled in the PRA and so failure of the drywell spray will be used as a surrogate for the associated RICT calculation. The basis provided is that the drywell and wetwell airspaces are connected by the downcomers. However, separate containment spray systems are provided in each airspace specifically because different environmental (temperature, pressure) conditions between the two air spaces are expected during severe accidents.

Provide additional justification that removal from service of a drywell spray loop is an appropriate surrogate for removal of a wetwell spray loop. The justification should include discussion of differences in the flowrates and availability/reliability of the two systems.

Response

The suppression pool spray system is not modeled in the PRA model since its flow rate is very limited (500 gpm) compared to that which would exist from operating the RHR system in either suppression pool cooling mode (10,000 gpm) or drywell spray mode (9,500 gpm)

(Reference APLA RAI-09.1). There would be insufficient flow for suppression pool spray to provide adequate containment heat removal alone. The Mark II containment design with a full concrete containment and with downcomers and vacuum breakers ensure that the

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 14 of 42 Docket Nos. 50-352 and 50-353 pressure differences between the wetwell and drywell region do not drastically differ during long term post-trip conditions. Limerick procedures specify initial operation of suppression pool sprays before 7.5 psig, but then require operation of drywell sprays if the containment pressure continues to rise above 7.5 psig. Ultimately, operation of RHR in suppression pool cooling or drywell spray mode is required to provide adequate containment heat removal and avoid approaching the Primary Containment Pressure Limit (PCPL) upon which venting of containment would be directed. Note that drywell sprays are also credited in the Level 2 analysis to provide a source of water on the drywell floor. Suppression pool sprays could not perform that function.

The only function of suppression pool spray addressed in the TS (see TS 3.6.2 and Bases 3/4.6.2) is containment heat removal for pressure control. Thus, utilizing the drywell spray trains as a surrogate for the suppression pool spray trains will provide a conservative representation of removing those trains from service.

b. For LCO 3.6.3.a (One or more Primary Containment Isolation Valves inoperable), LAR Table E1-1 states that lines less than two inches in diameter are not considered a significant leakage path, and that for containment isolation valves greater than two inches that are not modeled in the PRA a generic isolation failure event will be used. Address the following:

i. Provide justification that failure of containment penetration lines less than two inches in diameter either do not contribute to LERF or are insignificant contributors to LERF.

Response

The basis for excluding penetration lines of less than 2-inch diameter from LERF contributors is NUREG/CR-3539 (Reference APLA RAI-09.2) and NUREG/CR-5565 (Reference APLA RAI-09.3), as noted in the Limerick Individual Plant Examination report (Reference APLA RAI-09.4).

The containment isolation pathways that screened in the FPIE PRA based on line size (2 inches or less in diameter) were re-evaluated for the Fire PRA due to the increased likelihood of multiple spurious operations due to fire induced hot shorts.

Based on this screening review, no new containment penetration lines were added to the containment bypass logic in the Fire PRA model.

ii. Describe the types of containment isolation valves greater than two inches that are not modeled in the PRA and provide justification why the proposed surrogate adequately captures the risk impacts.

Response

The containment isolation valves greater than two inches that are not modeled in the Limerick PRA fall into the following groups.

• First are penetrations for RCS connections (Type A Penetrations). These include feedwater, CRD lines, RCIC steam line, shutdown cooling system lines (pump suction) and low pressure ECCS injection lines. The Level 1 PRA addresses isolation failures in these lines as initiating events (LOCAs, breaks outside containment and high-low pressure interface or high energy line break).

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 15 of 42 Docket Nos. 50-352 and 50-353

• Second are penetrations for closed loop piping systems (Type B & C Penetrations). These penetrations create a release path only if: (a) piping failures occur inside or outside containment, and (b) containment isolation valves fail to close. These would include the Drywell chilled water system and recirculation pump seal cooling. The joint probability of such release paths is found to be negligible so they are not modeled.

In implementing the RTR model, all containment isolation valves subject to TS 3.6.3.a that are not explicitly modeled will be mapped to an isolation path failure event which leads to containment isolation failure in the PRA.

Note that penetration line size greater than two inches is not pertinent to the choice of valve selected, because the LERF model does not distinguish magnitude of release; a sequence either leads to LERF or does not.

c. LAR Table E1-1 makes generic statements that the SSCs covered by LCOs are modeled in the PRA but does not describe how. For each LCO listed below describe how the SSCs are modeled in the PRA, describe its impact on CDF and/or LERF, and justify how a RICT can be quantitatively determined.

i. LCO 3.1.5.1.a: (Standby liquid control system) Only one pump and corresponding explosive valve OPERABLE

Response

The standby liquid control system is explicitly modeled in the PRA. Pumps, valves, initiation logic and required support systems are included. The RICT is calculated by failing the train(s) that are non-functional. This is the same as is done for 10CFR50.65(a)(4) online risk assessments.

ii. LCO 3.6.4.1.a: One or more vacuum breakers in one of the three required pairs of vacuum breakers inoperable for opening but known to be closed

Response

The vacuum breakers are modeled at the system level. The PRA addresses the impact of both vacuum breaker failure to open when required, and vacuum breaker inadvertently open when required to be closed. The assumed impact in the model is the same for either failure mode, i.e., failure of containment resulting in LERF, as described in Table 3.3-3 of the Limerick Level 2 Notebook. Since the individual vacuum breakers are not modeled, the system function will be failed to conservatively calculate the RICT impact of one or more vacuum breakers inoperable.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 16 of 42 Docket Nos. 50-352 and 50-353 iii. LCO 3.7.8: Main Turbine Bypass System Inoperable

Response

The PRA models the main turbine bypass valves at a system level as part of reactor pressure control (failure of the function) so failing this input to the pressure control function in the RICT calculation will be conservative.

References APLA RAI-09.1 Limerick Updated Final Safety Analysis Report, Revision 19, September 2018.

APLA RAI-09.2 NUREG/CR-3539, Impact of Containment Building Leakage on LWR Accident Risk, Oak Ridge National Laboratory, April 1984.

APLA RAI-09.3 NUREG/CR-5565, the Response of BWR Mark II Containments to Station Blackout Severe Accidents, May 1991.

APLA RAI-09.4 Limerick Generating Station, Units 1 and 2, Individual Plant Examination, Philadelphia Electric Company, July 1992.

APLA RAI LCO 3.6.5.3, Standby Gas Treatment (SGTS)

The LAR proposes that LCO 3.6.5.3, Standby Gas Treatment, is in the scope of the RICT program. LAR Attachment 4 recognizes that LCO 3.6.5.3 is not in scope of TSTF-505, consistent with Item 11 in Section 2.3 of TSTF-505, Revision 2 that states:

The traveler will not modify Required Actions for systems that do not affect core damage frequency (CDF) or large early release frequency (LERF) or for which a RICT cannot be quantitatively determined.

LAR Attachment 4 further states that SGTS is modeled in the Limerick PRA and that a quantitative RICT can be performed for this TS but does not describe the PRA modeling for this LCO. According to Section 6.5.1.1 of the Limerick Updated Final Safety Analysis Report, the SGTS function is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a Design Basis Accident (DBA) are filtered and adsorbed prior to exhausting to the environment. This function mitigates the radiological consequences following DBAs and ensures that the offsite and onsite radiological dose does not exceed the limits stated in 10 CFR 50.67. The NRC staff notes that this system function does not appear to have any impact on CDF and LERF. Therefore, address the following:

a. Describe the functions of the SGTS system and explain how the proposed change is consistent with RG 1.174, Revision 3, key principles 2 and 3 regarding maintaining defense-in-depth and safety margins.

b. Describe and justify how the SGTS functions identified in part a above are modeled in the PRA and how the numerical impact on CDF and/or LERF can be estimated.

c. Alternatively, to items a and b, remove LCO 3.6.5.3 from the scope of the RICT program.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 17 of 42 Docket Nos. 50-352 and 50-353

Response

The following LCOs will be removed from the scope of the RICT program.

3.6.5.3.a.1 (Unit 1) - One SGTS subsystem inoperable 3.6.5.3.a.2 (Unit 2) - One SGTS subsystem inoperable 3.6.5.3.a.3 (Unit 2) - One SGTS subsystem inoperable and other Unit 1 EDG inoperable 3.6.5.3.a.4 (Unit 2) - Unit 1 EDGs for both SGTS subsystems inoperable B. PRA LICENSING BRANCH B (APLB) RAIS APLB RAI Bounding Seismic Risk Analysis Section 2.3.1, Item 7, of NEI 06-09, Revision 0-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 (ADAMS Accession No. ML071200238) 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.

A seismic PRA model is not available for LGS. In Section 3 of Enclosure 4 to the LAR, the licensee stated that a seismic core damage frequency (CDF) and large early release frequency (LERF) penalty was determined for this application using the recent seismic hazard curves developed in response to Recommendation 2.1 of the Near-Term Task Force (NTTF) (ADAMS Accession No. ML14090A236).

Details of the approach for determining the seismic penalty are provided in Section 3 of to the LAR. The licensee calculated the seismic LERF using the ratio between LERF and CDF, based on the internal events, including internal flooding. The licensee explained that the ratio was adjusted by removing the risk contribution of certain accident scenarios because they would not be expected to be induced by a seismic event. In Section 3 of Enclosure 4 to the LAR, the licensee stated that the chosen conditional large early release probability (CLERP) value was adequately conservative. As noted earlier, the NEI 06-09, Revision 0-A, as well as the corresponding NRC staff SE, calls for a bounding analysis. In addition, NRC staff observes that LERF-to-CDF ratio for seismic events can be significantly higher than the same ratio for internal events due to the unique nature of seismically-induced failures. It is unclear that the selected CLERP of 20% can be considered as a bounding value for use in the RICT calculation.

a. Justify that the seismic LERF penalties provided in the submittal to support RICT calculations for LGS are bounding. Include the rationale that deriving seismic LERF-to-CDF ratio using the internal events LERF-to-CDF ratio is bounding for seismically induced events, given that internal events random failures do not capture seismically-induced failures that may uniquely contribute to LERF.

Response

Throughout NEI 06-09 Rev 0-A and the NRC SE for that document, reference is made to either a bounding or conservative analysis, or sometimes to a reasonable bounding

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 18 of 42 Docket Nos. 50-352 and 50-353 analysis, as being acceptable to account for risk for external hazards when a PRA model is not available. The references to estimation of a seismic LERF contribution for the RICT program as bounding should more accurately refer to this as a conservative analysis that uses an estimated averaged seismic conditional large early release probability (SCLERP) to determine a seismic LERF that is then conservatively used in RICT assessments. A truly bounding estimate for seismic LERF would require assuming SCLERP = 1.0, which is neither reasonable nor realistic.

In the absence of a current seismic PRA for Limerick, the approach used to estimate SCLERP for the LAR was to use the internal events and internal flooding PRAs to derive a CLERP value for each initiating event (i.e., large early release frequency for the initiating event divided by core damage frequency for the initiating event) in those PRAs for all initiating events other than direct containment bypass events. That approach could not be shown to be sufficiently conservative in addressing the influence of seismic-induced failures, so the estimation of the average SCLERP may not be sufficiently conservative. The response to Part (b) provides an alternate assessment of a conservative approach to providing seismic LERF penalties for use in RICT calculations.

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

Response

As an alternative to the approach proposed in the LAR, available information from a seismic PRA analysis previously performed for Limerick as noted in Section 1.1 of the Limerick Updated Final Safety Analysis Report (UFSAR) (APLB RAI-01.1), i.e., the 1983 Limerick Severe Accident Risk Assessment (SARA) study (Reference APLB RAI-01.2), which was updated in 1989 (Reference APLB RAI-01.3), is used here in an approach to estimate an average seismic CLERP that combines seismic insights from the SARA along with Level 2 accident sequence information from the current Limerick internal events PRA. Based on the alternative approach, an SCLERP of 0.5 is derived as a conservative value for use in the seismic LERF penalties for the RICT calculations. The application of the SLERF estimate in the RICT process is also conservative. Both these aspects are discussed below.

Detailed Discussion of Alternative Approach Based on information from the 1983 Limerick SARA report (Reference APLB RAI-01.2), the alternative approach considers a reasonable spectrum of Level 1 seismic-induced accidents, Level 2 accident sequence progression and the influence of seismic-induced failures. This alternative approach is discussed below according to the following topics:

• Overview of Limerick SARA seismic analysis

• Spectrum of seismic-induced core damage accident sequence types

• CLERP as a function of seismic core damage accident sequence type

• Application of SLERF in RICT Calculations Overview of Limerick SARA Seismic Analysis The 1983 Limerick SARA was performed in support of the response to a 1980 US NRC request for a probabilistic risk assessment of severe accidents for the new Limerick plant.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 19 of 42 Docket Nos. 50-352 and 50-353 The 1983 Limerick SARA study formed part of the response; it addressed external events, including seismic, during at-power operation and documented a Level 3 PRA analysis (i.e.,

from initiating event to offsite consequences) to supplement the risk insights from the internal events at-power PRA analysis. This study was reviewed by Brookhaven National Laboratory (BNL) in NUREG/CR-3493 (Reference APLB RAI-01.4). The Limerick SARA was subsequently updated in 1989. While the update of the original study resulted in some differences in the contributions of various accident sequences, the contributors significant to the development of the seismic LERF estimate for the Limerick TSTF-505 application remained sufficiently similar to support this assessment, as discussed below.

The Limerick-specific SARA seismic PRA includes the following three fundamental technical areas:

• Seismic hazard analysis

• Response and fragility analysis

• SPRA systems and accident sequence analysis The seismic hazard analysis was performed using methodologies of the early 1980s and covered the typical aspects of seismic sources, attenuation and site amplification. Hazard exceedance curves and ground motions were provided. The SPRA analysis was performed for the g-PGA (peak ground acceleration) motion metric.

The fragility analysis was primarily plant-specific and used existing Limerick structure and equipment analyses as input information. Structural fragilities were performed for the following:

• Primary containment (limiting fragility: flexure failure of shield wall, median fragility, Am=1.6g)

• Reactor Enclosure (RE) and Control Enclosure (CE; limiting fragility: CE shear wall impacting both CE and RE, Am=1.05g)

• Spray Pond Pump Structure (limiting fragility: shear wall, Am=3.2g)

• Diesel Generator Enclosure (limiting fragility: shear wall, Am=1.4g)

The equipment considered for fragility analysis was identified from the Limerick at-power internal events PRA models. Fragility calculations covered hundreds of equipment items and the typical spectrum of equipment types (e.g., pumps, heat exchangers, tanks and accumulators, buses and transformers, circuit breakers, reactor internals, NSSS piping, non-NSSS piping, valves, cable trays, strainers, etc.). Fragilities were calculated using the Gaussian mathematical model of a fragility curve (the most common fragility model in NPP SPRAs) defined by a median failure acceleration (Am) and two lognormally distributed uncertainty statistics Br (randomness) and Bu (uncertainty).

The PGA seismic hazard curve and fragility information were integrated into the Limerick internal events at-power PRA for the quantification of the seismic PRA. The SARA SPRA explicitly quantified the following types of accident sequences:

• Direct to Core Damage: Significant seismic-failures leading directly to core damage (e.g., RPV support failure, RE and CE structure failures)

• Seismic LOOP: Seismic induced loss of offsite power and reactor scram successful

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 20 of 42 Docket Nos. 50-352 and 50-353

• Seismic LOOP ATWS: Seismic induced loss off offsite power with reactor scram failure LOCAs and ISLOCAs were identified and fragilities estimated but these sequences were not explicitly modeled in the SARA due to low risk significance based on their comparatively high seismic capacities (e.g., NSSS piping median capacities of Am 2g). Seismic transients (offsite power intact) were also not explicitly modeled due to low risk significance given the very low capacity of offsite power (Am=0.2g).

Spectrum of Seismic-Induced Core Damage Accident Sequence Types The estimation of an averaged SCLERP requires as an input the assessment of the contribution of different accident sequence types to seismic core damage frequency (SCDF). The contribution of various accident sequence types (or accident classes) to core damage frequency at a given plant is not necessarily the same between at-power internal events PRA and other hazard (e.g., seismic) PRAs. Although the Limerick SARA was performed prior to the development of current SPRA methods and standards, that study does provide useful insights into seismic accident sequences. Therefore, the results from the Limerick SARA seismic analysis are used here to define the spectrum of seismic-induced accident sequences types to SCDF.

The categories of SCDF sequence types considered are as follows:

• Seismic-Transients with early loss of injection: These sequences have offsite power available (and thus potential use of balance of plant equipment, e.g., Feedwater) but RPV coolant injection failure at t=0.

• Seismic-Transients with loss of containment cooling: These sequences have offsite power available (and thus potential use of balance of plant equipment, e.g.,

Feedwater), RPV coolant makeup is initially successful but containment cooling (e.g.,

RHR) is not successful. Adequate core cooling is subsequently failed (e.g., harsh environment in reactor enclosure) due to primary containment overpressurization and failure.

• Seismic-LOOP with early loss of injection: These are seismic-induced loss of offsite power scenarios with RPV coolant injection failure at t=0.

• Seismic-LOOP with loss of containment cooling: These are seismic-induced loss of offsite power scenarios with RPV coolant makeup initially successful but containment cooling (e.g., RHR) is not successful. Adequate core cooling is subsequently failed (e.g., harsh environment in reactor enclosure) due to primary containment overpressurization and failure.

• Seismic-LOOP with Seismic-LOCA and early loss of injection: These are scenarios with a seismic-induced LOOP and seismic-induced LOCA (small, medium or large) and RPV coolant injection failure at t=0. Given the very high capacity of NSSS piping in comparison to the very low capacity of offsite power, the contribution of Seismic-LOCA with offsite AC available to seismic risk is negligible.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 21 of 42 Docket Nos. 50-352 and 50-353

• Seismic-LOOP with Seismic-LOCA and loss of containment cooling: These are scenarios with a seismic-induced LOOP and seismic-induced LOCA (small, medium or large) with RPV coolant makeup initially successful but containment cooling (e.g.,

RHR) is not successful. Adequate core cooling is subsequently failed (e.g., harsh environment in reactor enclosure) due to primary containment overpressurization and failure. Given the very high capacity of NSSS piping in comparison to the very low capacity of offsite power, the contribution of Seismic-LOCA with offsite AC available to seismic risk is negligible.

• Seismic-ATWS Unmitigated: These are seismic-induced failure to scram scenarios with failure of reactivity control (e.g., failure of standby liquid control). These accidents proceed with high reactor power discharge into containment resulting dynamic loading and failure of the primary containment. Adequate core cooling is failed (e.g., harsh environment in reactor enclosure) upon primary containment failure.

• Direct to Core Damage: These are scenarios with significant seismic-induced failures that are modeled directly as core damage. Such scenarios include key structural failures (e.g., RPV support failure, RE and CE structural failure) and ISLOCA scenarios.

The above accident sequence categories cover the key critical safety functions (reactivity control, core cooling, RPV and primary containment integrity) and are sufficient to describe the spectrum of SCDF accident sequences.

Based on the seismic accident sequence results in the Limerick SARA study, the spectrum of Limerick SCDF accident sequence types is summarized in Table LG-APLB01-1 below, along with their percentage contributions to the SARA seismic CDF results. The largest contribution (55%) to SCDF was from seismic-induced LOOP scenarios with early loss of coolant injection (e.g., seismic-induced loss of 125V DC, seismic-induced loss of AC buses);

this result is typical of BWR SPRAs. The next two most dominant accident sequence types were Direct to Core Damage (33%) and ATWS (10%). The high contribution from these second and third sequence types are due to two comparatively low fragilities and conservative modeling of their effects (i.e., Am=1.05g for Control Enclosure shear wall failure that causes significant failures to both CE and RE equipment and thus all core cooling modeled as failed; and Am=0.67g for core shroud support modeled as causing failure of all control rods to insert). The non-significant contribution from LOCAs and seismic-transients is typical of BWR SPRAs. Table LG-APLB01-1 also provides the same information for the 1989 update to SARA, and the dominant contributors are the same in both studies.

CLERP as a Function of SCDF Accident Sequence Type The next step in the estimation of an averaged SCLERP is to estimate the SCLERP for each SCDF accident sequence type. A given accident sequence type may not result in a core damage event until well after the PRA Early release time frame (defined in the LGS at-power internal events PRA as 9.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> from the time of the cue for a General Emergency declaration). Conversely, some accident sequence types would, by PRA convention, be modeled directly as a LERF, such as an unisolated ISLOCA scenario or reactor enclosure

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 22 of 42 Docket Nos. 50-352 and 50-353 structural failure. SCLERP as a function of SCDF accident sequence type is summarized in Table LG-APLB01-1, for both the original SARA and for the 1989 update.

Based on the information in Table LG-APLB01-1, an estimate of SCLERP based on the original SARA results is 0.44, i.e., seismic LERF is equal to 44% of the seismic CDF estimate. The estimate using the 1989 update results is 0.48. Although the sequence-specific percentage of CDF contributions for the top four accident sequence types changed, they are the same dominant contributors in the same rank order and the conservatism applied in assigning SCLERP for the direct to core damage and ATWS contributors results in a similar average SCLERP estimate. To account for potential uncertainties in the SCLERP calculation for use in RICT calculations for Limerick, an SCLERP of 0.5 will be used as a conservative value to provide additional safety margin for use in the seismic LERF penalties for the RICT calculations.

For RICT calculations for de-inerted conditions, the SCLERP would be 1.0 as stated in the Limerick TSTF-505 LAR (Reference APLB RAI-01.5).

Application of SLERF in RICT Calculations Conservatism in the RICT process derives from the proposed approach to apply the total estimated annual seismic LERF as a delta SLERF in each RICT calculation, regardless of the duration of the completion time. The total estimated annual seismic CDF and LERF will be applied starting at time zero for each RICT calculation. Given that the maximum (backstop) completion time is 30 days, use of the annual seismic LERF (and seismic CDF) in the RICT calculations introduces a factor of at least 12 conservatism in the seismic contribution to each RICT calculation.

References APLB RAI-01.1: Limerick UFSAR, Section 1.1 (Introduction).

APLB RAI-01.2: Limerick Generating Station Severe Accident Risk Assessment, Philadelphia Electric Company, April 1983.

APLB RAI-01.3: PECO letter to NRC, Limerick Generating Station, Units 1 and 2 Response to Request for Additional Information Regarding Consideration of Severe Accident Mitigation Design Alternatives, June 23, 1989.

APLB RAI-01.4: NUREG/CR-3493, A review of the Limerick Generating Station Severe Accident Risk Assessment, USNRC, July 1984.

APLB RAI-01.5: Letter from J. Barstow (Exelon Generation Company, LLC) to U.S.

Nuclear Regulatory Commission, License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b'," dated December 13, 2018 (ADAMS Accession No. ML18347B366).

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 23 of 42 Docket Nos. 50-352 and 50-353 Table LG-APLB01-1 SPECTRUM OF SCDF ACCIDENT SEQUENCES AND ASSOCIATED SCLERP Limerick SARA SCLERP %SCDF SCLERP Study %SCDF 1983 1983 1989 1989 L1 SPRA Study(1)

Study(2) Update(3) Update(2)

Sequence Type Comment S-LOOP with 55% 1.1E-02 53% 1.1E-02 Based on CLERP results for LOOP with no injection at t=0 early loss of accidents with no AC recovery and no coolant injection injection recovery in LGS FPIE Level 2 PRA. LGS Mark II primary containment does not have steel shell liner with air gap (such as in Mark I containments) and thus likelihood of a "High" magnitude release for an unmitigated core damage accident is lower in comparison to a Mark I containment design.

Scenarios direct 33% 1 43% 1 SCLERP slightly conservative (e.g., some such contributors to core damage would not be directly High Magnitude/Early release, e.g., CE (e.g., RPV failure alone).

support failure, RE and CE structural failures, ISLOCA)

S-ATWS 10% 1 5% 1 SCLERP conservative because LGS L2 PRA conservatively unmitigated does not credit the Reactor Enclosure for radionuclide filtration. With RE credit the SCLERP could be reduced.

S-LOOP with loss 2% 5.0E-02 <1%(4) 5.0E-02 Declaration of a general emergency would be in accordance of containment with LGS Emergency Action Levels. However, the LGS PRA cooling includes a 5% probability that the General Emergency declaration is delayed and thus can result in an "Early" release for these sequences. Using the 5E-02 SCLERP value is conservative because it does not account for the primary containment failure location in reducing release magnitude (i.e., if failure occurs in the wetwell airspace the release would be scrubbed and not a "High" magnitude release).

S-LOOP with S- <1% 1.0E-02 <1% 1.0E-02 SCLERP would be similar to LGS FPIE LOOP case above LOCA with early except containment failure due to certain energetic loss of injection phenomena (e.g., direct containment heating; high pressure blowdown overwhelming vapor suppression) is precluded or much lower likelihood given the LOCA condition.

S-LOOP with S- <1% 5.0E-02 <1% 5.0E-02 Same basis discussed above for S-LOOP with loss of LOCA and loss of containment cooling.

containment cooling S-Transients (no <1% 1.1E-02 <1% 1.1E-02 Based on LGS FPIE PRA, LOOP with no injection at t=0 LOOP) with early accidents with no AC recovery and no coolant injection loss of injection recovery in Level 2 PRA.

S-Transients (no <1% 5.0E-02 <1% 5.0E-02 Same basis discussed above for S-LOOP with loss of LOOP) with loss containment cooling.

of containment cooling Sequence-Weighted Averaged 0.44 0.48 Sum of (%SCDF x SCLERP) over all sequences SCLERP:

Notes to Table:

(1) SCDF accident sequence type contribution based on information and quantification results in Section 3, Table 3-2 and Appendices B and C of the 1983 Limerick SARA seismic PRA (Reference APLB RAI-01.2).

(2) Seismic conditional large early release probability values are based on insights from similar sequences as modeled in the Limerick internal events PRA, per the discussion in the Comment column.

(3) SCDF accident sequence type contribution based on information and quantification from the 1989 Limerick SARA seismic PRA update (Reference APLB RAI-01.3). Percentages shown in table do not exactly total to 100% because 2-digit precision shown in table for the risk contributions (the full precision percentage contribution values total to 100% exactly and are used in the actual calculation).

(4) The <1% risk contributions are non-significant contributors and are treated as 0% in the average SCLERP calculation.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 24 of 42 Docket Nos. 50-352 and 50-353 APLB RAI Extreme Winds Analysis Section 2.3.1, Item 7, of NEI 06-09, Revision 0-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 SE for NEI 06-09 (ADAMS Accession No. ML071200238) 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. Section 1.2.5 of Regulatory Guide (RG) 1.200, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-informed Activities, Revision 2 (ADAMS Accession No. ML090410014), states that the contribution of many external events to CDF and LERF can be screened out (1) if it meets the criteria in the NRCs 1975 Standard Review Plan (SRP) or a later revision; or (2) if it can be shown using a demonstrably conservative analysis that the mean value of the design-basis hazard used in the plant design is less than 10-5 per year and that the conditional core damage probability is less than 10 -1, given the occurrence of the design-basis-hazard event; or (3) if it can be shown using a demonstrably conservative analysis that the CDF is less than 10-6 per year. The screening criteria listed in Section 1.2.5 of RG 1.200 are consistent with those in Section 6-2.3 of the 2009 American Society of Mechanical Engineers/American Nuclear Society (ASME/ANS) PRA Standard (RA-Sa-2009), "Addenda to ASME/ANS RA-S-2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications."

In Section 4 of Enclosure 4 to the LAR, the licensee addresses the risk from extreme winds.

The tornado generated missile damage determined by a 1984 hazard analysis that the likelihood of the loss of the ultimate heat sink (UHS) was approximately 8x10-7/yr. A comparison of tornado frequencies was made by the licensee between those in the 1984 hazard analysis and data from NUREG/CR-4461, Revision 2, Tornado Climatology of the Contiguous United States, February 2007 (ADAMS Accession No. ML070810400) which showed that estimated tornado frequencies have reduced by more than an order of magnitude from the 1984 hazard analysis. Section 4 of Enclosure 4 to the LAR also states that the 1984 PRA shows that the only damage is from Fujita Scale F4 and greater tornadoes (>206 miles/hour) and that high wind and hurricane frequencies are negligible. Based on the information in the LAR, it is unclear to the staff whether the licensees approach appropriately considers the risk of tornado missile impact for this application.

a. Justify that the loss of UHS is the only non-conforming SSC impacted by tornado generated missiles. If additional impacts exist, discuss and justify how the impact of tornado missiles on such structures, systems, and components (SSCs) is addressed in the context of this application.

Response

Per Enclosure 4 of the TSTF-505 LAR (page E4-8):

Section 3.5.1.4 of the LGS UFSAR (Reference 15) describes the capability of safety related structures to protect SSCs against tornado missiles and protection of the ESW and RHRSW system yard piping by burial. LGS is in conformance with Regulatory Guide 1.117 regarding systems to be protected from tornado missiles, except for unprotected parts of the ESW and RHRSW systems and spray pond networks.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 25 of 42 Docket Nos. 50-352 and 50-353 The LGS IPEEE (Reference APLB RAI-02.1) confirmed that the plant was protected against tornado missiles as described in the UFSAR, with the exception of the spray pond. More recently, LGS performed an evaluation of the current licensing basis with respect to tornado missile protection in response to Regulatory Information Summary 2015-06 (Reference APLB RAI-02.2). It was determined that LGS conforms to all aspects of the current licensing basis and is adequately protected against tornado missiles (Reference APLB RAI-02.3).

Therefore, there are no additional tornado missile non-conformances at LGS.

b. Describe the approach used to determine the impact of tornado missiles on the likelihood of the loss of UHS and justify its applicability to the screening of tornado missile risk for the proposed RICT program. Include a discussion on (i) the basis for concluding that only tornado category F4 and greater are relevant to this application and (ii) how the frequency and potential for damage from exposure to tornadoes and high winds that are less than F4 are addressed.

Response

The total risk is based upon the UHS Extreme Wind Hazard Analysis (NUS-4507; Reference APLB RAI-02.4) and associated correspondence between PECO and NRC (e.g., RAIs)

(References APLB RAI-02.5 - APLB RAI-02.7). This analysis was reviewed by NRC as part of the LGS SER (Reference APLB RAI-02.8). Note: NUS-4507 is referred to as the 1984 PRA on page E4-9 of the LGS TSTF-505 LAR. They are one and the same.

Base Results As described in Enclosure 4 of the TSTF-505 LAR, the tornado missile (TM) CDF is estimated to be 8E-7/yr, which is <1E-6/yr. A comparison of recent tornado hazard information provided in NUREG/CR-4461 (Reference APLB RAI-02.9) shows that the frequency of tornadoes is more than a factor of 10 lower than the tornado frequency used in NUS-4507. Therefore, the total tornado missile risk for LGS is even lower than reported in NUS-4507.

Comparison of Tornado Wind Speeds Wind Speed Frequency from Frequency from Ratio (mph) NUS-4507 NUREG/CR-4461 NUS-4507:

Table 3-4 Curve Fit NUREG/CR-4461 200 4E-5/yr 1.1E-6/yr 36 250 5E-6/yr 1.3E-7/yr 38 300 2E-7/yr 1.6E-8/yr 12 The statement in Enclosure 4 of the TSTF-505 LAR is not intended to conclude that only F4 and greater tornadoes are relevant to or considered in this application. Rather, it is referring to the results of the NUS-4507 analysis, which showed that F1 - F3 tornadoes did not contribute to the total loss of UHS frequency. Table 5-1 in NUS-4507 provides the frequencies for the loss of all UHS (designated Events T and V), which require the loss of the spray pond network and the cooling towers. Responses to NRC questions on NUS-

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 26 of 42 Docket Nos. 50-352 and 50-353 4507 (in 1984) acknowledged that F1 - F3 tornadoes can damage the spray networks and are considered in the hazard analysis (see response to Q2 in Reference APLB RAI-02.5).

Configuration Specific Results The tornado missile-induced loss of UHS frequencies in NUS-4507 and associated RAI responses do not account for maintenance configurations. With two units operating, the failure criteria in Loss of all UHS Event V is the loss of three-of-four spray networks and both cooling towers. Since Technical Specifications allow up to two spray networks to be inoperable, the loss of a single spray pond network and the cooling towers will result in a loss of UHS with both units operating.

Table 4 of Reference APLB RAI-02.5 provides the conditional likelihood of missile damage to the spray networks, based on tornado intensity. Table 4 conditional probabilities are mutually exclusive; they represent the likelihood of exactly n spray networks damaged.

Table 4 is summarized in the table below.

CONDITIONAL PROBABILITY OF NETWORK DAMAGE GIVEN TORNADO STRIKE F-Scale 3 4 3 or 4 Any Number Ratio Any Intensity Networks Networks Networks of Networks Networks: 3 Damaged Damaged Damaged(a) Damaged (b) or 4 Networks F1 <0.005 0 <0.005 0.03 >6(c)

F2 0.07 0.05 0.12 0.21 1.8 F3 0.05 0 0.05 0.15 3.0 F4 0.07 0.04 0.11 0.45 4.1 F5 0.12 0.06 0.18 0.40 2.2 Notes:

(a) Sum of 3 Networks Damaged + 4 Networks Damaged (b) Any Number of Networks Damaged = 1.0 - (probability of 0 networks damaged) from Table 4.

(c) 0.03/0.005 = 6.

In the limiting case where two spray pond networks are unavailable, damage to a single spray network and both cooling towers will result in the loss of UHS. Depending on the intensity of the tornado, it is up to four times more likely that one or more networks are damaged as compared to damaging three or four networks (i.e., F4: 0.45 vs 0.11). Note that F1 results are not considered relevant in this case, since F1 winds will not fail both the cooling towers and the spray networks (Reference APLB RAI-02.4).

An increase in configuration CDF1 by a factor of four over the base CDF would be approximately 3E-6/yr (8 E-7 x 4.1 = 3.3E-6). However, considering that the current tornado frequency is lower by at least an order magnitude, the configuration CDF would be on the order of 3E-7/yr, or lower. Therefore, the frequency of the total loss of UHS with two spray 1

It is conservatively assumed that loss of all UHS results in a conditional core damage probability of 1.0.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 27 of 42 Docket Nos. 50-352 and 50-353 networks unavailable would still be less than 1E-6/yr considering the more recent hazard information. This is the most restrictive maintenance configuration, as it requires only the loss of a single spray network to result in loss of UHS.

The site conditions and assumption used in the NUS-4507 analysis were reviewed against the current plant status. In response to Q1 in Reference APLB RAI-02.5, a summary of conservatisms was provided (see 7. Summary). The summary estimates significant conservatisms in the NUS-4507 analysis, with magnitudes ranging from factors of 2 to 30.

Considering the potential changes to the site since the publication of NUS-4507, the number of missiles on site is the main parameter that may have changed and could result in higher damage frequencies. Per Table 1 of Reference APLB RAI-02.5, the total number of missiles estimated for the site is approximately 120,000; this parameter is assessed as very conservative in Table 1. It is further noted in response to Q1, that the number of missiles are based on a period of heavy construction, which would generally be reduced following completion of construction. Even if the current missile population were double the estimated missiles in NUS-4507 and the damage frequencies doubled as a result, the frequencies for Loss of all UHS Event T and V would still be less than 1E-6/yr, considering the more recent (lower) tornado frequencies.

It is also noted that the loss of UHS, as defined in NUS-4507, does not necessarily result in core damage, although it is conservatively assumed to do so. As described in the UFSAR, damage to spray networks does not result in a complete loss of heat removal capability, and procedures exist to effect repairs to damaged spray networks following a severe weather event (e.g., SE 9-4, Repair to Spray Pond Networks; Reference APLB RAI-02.10).

c. If tornadoes and high winds cannot be screened based on the responses to the above questions, discuss how the risk for these hazards will be addressed in the proposed RICT program.

Response

Based on the responses to parts a and b of this RAI, high winds remain screened for this application.

d. Clarify whether any SSCs are credited in the screening of tornadoes and high winds, including tornado missiles. If such SSCs exist discuss how it will be ensured that assumptions related to the availability and the functionality of those SSCs remain valid during RICTs such that the extreme wind hazard continues to have an insignificant impact on the configuration-specific risk.

Response

Only Category I structures that provide wind and missile protection to safety-related SSCs are credited in the screening of high winds and tornadoes; they are required to remain intact and functional during plant operations.

References APLB RAI-02.1 PECO Energy Company, Limerick Generating Station Units 1 and 2, Individual Plant Examination for External Events, June 1995.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 28 of 42 Docket Nos. 50-352 and 50-353 APLB RAI-02.2 Regulatory Information Summary 2015-06, Tornado Missile Protection, June 10, 2015.

APLB RAI-02.3 Limerick EC 0000620209, Tornado Missile Project, Revision 0, January 11, 2018.

APLB RAI-02.4 NUS-4507, Limerick Generating Station - Ultimate Heat Sink Extreme Winds Hazard Analysis, March 1984.

APLB RAI-02.5 Letter from J. Kemper, Philadelphia Electric Company to A. Schwencer, U.S. NRC, Limerick Generating Station, Units 1 & 2 Additional Information for Auxiliary Systems Branch Regarding SER Open Issue #2 (Tornado Missile Effects on Ultimate Heat Sink), September 4, 1984.

APLB RAI-02.6 Letter from J. Kemper, Philadelphia Electric Company to A. Schwencer, U.S. NRC, Limerick Generating Station, Units 1 & 2 Additional Information for Auxiliary Systems Branch Regarding SER Open Issue #2 (Tornado Missile Effects on Ultimate Heat Sink), September 11, 1984.

APLB RAI-02.7 Letter from J. Kemper, Philadelphia Electric Company to A. Schwencer, U.S. NRC, Limerick Generating Station, Units 1 & 2 Additional Information for Auxiliary Systems Branch Regarding SER Open Issue #2 (Tornado Missile Effects on Ultimate Heat Sink), September 21, 1984.

APLB RAI-02.8 NUREG-0991, Safety Evaluation Report related to the operation of Limerick Generating Station, Units 1 and 2, May 1985.

APLB RAI-02.9 NUREG/CR-4461, Tornado Climatology of the Contiguous United States, Revision 2, February 2007.

APLB RAI-02.10 Limerick Generating Station Special Event Procedure SE 9-4, Repair to Spray Pond Networks, Rev. 10.

C. ELECTRICAL ENGINEERING OPERATING REACTOR BRANCH (EEOB) RAIS The regulatory requirements related to the content of the TSs are contained in Title 10 of the Code of Federal Regulations (10 CFR) Section 50.36, "Technical specifications." Section 50.36 (c) of 10 CFR requires TSs to include the following categories related to station operation:

(1) safety limits, limiting safety systems settings, and limiting control settings; (2);

limiting conditions for operation (3) surveillance requirements; (4) design features; (5) administrative controls; (6) decommissioning; (7) initial notification; and (8) written reports Section 50.36(c)(2)(i) of 10 CFR states, in part, Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 29 of 42 Docket Nos. 50-352 and 50-353 of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

10 CFR, Appendix A of Part 50, General Design Criterion (GDC) 17, Electric Power Systems, requires, in part, that an onsite electric power system and an offsite electric power system be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.

EEOB RAI-01:

UFSAR Section 3.1, Conformance with NRC General Design Criteria, Design Evaluation for Electric Power Systems states: Either of the two offsite power systems or any three of the four onsite standby diesel generator systems in each unit have sufficient capability to operate safety-related equipment so that specified acceptable fuel design limits and design conditions of the RCPB are not exceeded as a result of anticipated operational occurrences and to cool the reactor core and maintain primary containment integrity and other vital functions if there are postulated accidents.

UFSAR Section 8.1.5.2, Onsite Power System, states: The onsite Class 1E electric power system is divided into four independent divisions per unit. With the exception of the power supply requirements for the ESW system, the RHRSW system, the SGTS, CSCWS and the control room and control structure ventilation systems, which are common systems, any combination of three-out-of-four divisions of Class 1E power in each unit can shut down the unit safely and maintain it in a safe shutdown condition. Common loads for the ESW and RHRSW systems are split between the Unit 1 and Unit 2 Class 1E power systems. Common redundant loads for the SGTS, CSCWS and the control room and control structure ventilation systems are fed from Unit 1 Class 1E power supplies.

Any combination of three-out-of-four divisions (EDGs) is acceptable for a single failure.

However, for ECCS requirements (as stated in paragraph 6.3.1.1.2), an EDG operable configuration of 2 out of 4 is also acceptable.

TSTF-505, Revision 2, Model Safety Evaluation states that application of the RICT Program requires that there is no TS loss of function conditions.

Based on the above and the design success criteria listed in LAR Table E1-1, it appears that the following Actions for LCO conditions represent a loss of function (i.e., to ensure three-out-of-four divisions of Class 1E power in each unit are operable):

a. 3.8.1.1.b -Two diesel generators inoperable where design success criteria require three of four diesel generators to be operable

b. 3.8.1.1.b* footnote - Two diesel generators inoperable RHRSW piping replacement

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 30 of 42 Docket Nos. 50-352 and 50-353

c. 3.8.1.1.e.1 - For two train systems, one or more diesel generators inoperable

d. 3.8.1.1.e.1* footnote- For two train systems, one or more diesel generators inoperable RHRSW piping replacement

e. 3.8.1.1.h - One offsite circuit and two diesel generators inoperable Please confirm for each of the above Actions for LCO conditions, either: (1) Confirm and describe with supporting documentation (NRC approvals) how all design-basis functions are met without loss of safety function of emergency onsite power system when entering any of the conditions listed above consistent with LGS design and licensing basis or (2) Remove the proposed RICT from LGS TS to be consistent with TSTF 505, Revision 2. Please provide appropriate clarifications and TS markup.

Response

Upon further evaluation, it has been concluded that the following TS Actions represent a loss of function condition: 3.8.1.1.b, 3.8.1.1.e.1 and 3.8.1.1.h. As a result, application of a RICT is removed from these TS.

However, footnotes 3.8.1.1.b* and 3.8.1.1.e.1* do not represent a loss of function condition.

These footnotes are specific to the extended time when Residual Heat Removal Service Water (RHRSW) system piping repairs are being performed in accordance with TS LCO 3.7.1.1. To allow for the RHRSW system piping repairs, the 72-hour allowed outage time for two inoperable diesel generators (per unit) may be extended to 7 days consistent with TS 3.7.1.1, Actions a.3.a or a.3.b, as described in the footnote. This extension was approved by the NRC in Amendment Nos. 203 and 165 for LGS, Units 1 and 2, respectively (Reference EEOB RAI-01.1).

Under this circumstance, the remaining two EDGs per unit are required to be operable and protected by TS LCO 3.7.1.1, Action a.3.a or a.3.b, whichever is applicable depending on the loop of RHRSW piping being repaired. For TS 3.8.1.1.e, for two train systems, because of the protective actions required by TS LCO 3.7.1.1, Actions a.3.a or a.3.b, the EDG for at least one of the two trains will be operable and protected.

In addition, during the RHRSW system piping repairs, two EDGs per unit are administratively declared inoperable because their associated ESW loop, which provides cooling water support for the EDGs, is administratively declared inoperable to address a postulated passive piping failure in the one remaining operable RHRSW system return header (which provides the return path for the ESW loop) while the other RHRSW system return header is out of service for repair.

This does not meet the redundancy and separation requirements in GDC 44 but does not constitute a loss of function.

As documented in the Safety Evaluation for Amendment Nos. 203 and 165, The ESW loop that is administratively inoperable will, however, remain aligned for automatic initiation and will be capable of performing its intended design function. Therefore, since the ESW loop that functions as cooling water support for the administratively inoperable EDGs (two per unit) is fully functional, and the other EDGs (two per unit) are protected and operable, both ESW loops and all eight LGS EDGs are fully capable of performing their safety function during the RHRSW system piping repairs. Therefore, footnotes 3.8.1.1.b* and 3.8.1.1.e.1*, do not constitute a loss of function.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 31 of 42 Docket Nos. 50-352 and 50-353 The changes to the above TS are reflected in the revised TS markups provided in Attachment 2.

References EEOB RAI-01.1 Letter from P. Bamford (USNRC) to M. Pacilio (Exelon Generation Company, LLC), Limerick Generating Station, Units 1 and 2 - Issuance of Amendments Re: Allowed Outage Time Extensions to Support Residual Heat Removal Service Water Maintenance (TAC Nos. ME3551 and ME3552)," dated July 29, 2011 (ADAMS Accession No. ML111960066).

EEOB RAI-02: 2 of LAR describes the process for identification and implementation of Risk Management Actions (RMAs) applicable during extended CTs and provides examples of RMAs.

Please clarify specific RMAs and compensatory measures, in addition to the RMAs specified for 3.8.1.1.f (one offsite source inoperable), to maintain defense in depth and safety margins of offsite electric power system that would be required by the RICT for TS 3.8.1.1.g (two offsite circuits inoperable).

Response

The same actions listed in the LAR for Action 3.8.1.1.f, one offsite source inoperable, would be taken as possible for Action 3.8.1.1.g, two offsite circuits inoperable, and are repeated below:

1. Actions to increase risk awareness and control.

• Briefing of the on-shift operations crew concerning the unit activities, including any compensatory measures established, and review of the appropriate emergency operating procedures for a Loss of Offsite Power and station blackout including bus crossties.

• Notification of the TSO of the configuration so that any planned activities with the potential to cause a grid disturbance are deferred.

• Proactive implementation of RMAs during times of high grid stress conditions prior to reaching the RMAT, such as during high demand conditions.

2. Actions to reduce the duration of maintenance activities.

• For preplanned RICT entry, creation of a sub schedule related to the specific evolution which is reviewed for personnel resource availability

• Confirmation of parts availability prior to entry into a preplanned RICT.

• Walkdown of work prior to execution.

3. Actions to minimize the magnitude of the risk increase.

• Evaluation of weather conditions for threats to the reliability of remaining offsite power supplies.

• Deferral of elective maintenance in the switchyard, on the station electrical distribution systems, and on the main and auxiliary transformers associated with the unit.

• Protection of the remaining offsite source, including switchyard and transformer.

• Walkdown of operable switchyard for potential wind driven missiles.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 32 of 42 Docket Nos. 50-352 and 50-353

• Deferral of planned maintenance or testing that affects the reliability of DGs and their associated support equipment which affect common system availability. Treat the remaining offsite source as protected equipment.

• Implementation of 10 CFR 50.65(a)(4) fire-specific RMAs associated with the affected offsite source.

Additional actions would be as follows:

• Maximize and protect the remaining capability of the offsite sources.

• Protection of all DGs from both Units.

• Protection of HPCI and RCIC on both Units.

• Review of the procedure for cross tying 4kV buses within and between Units.

• Review of procedure for powering C and D ESW pumps from Unit 1.

• Deferral of activities that could increase the likelihood of a plant trip.

• If feasible based on the configuration, connection of the non-Tech Spec 66kV offsite source as an incoming power supply.

EEOB RAI-03:

UFSAR Section 8.3.1.1.3, Standby Power Supply, states: Common loads for the ESW and the RHRSW systems are split between Unit 1 and Unit 2 standby power supplies. Common redundant loads for the SGTS, the CSCWS and the control room and control structure ventilation systems are fed from Unit 1 standby power supplies. Staff notes that TS LCO 3.8.1.1b identifies only four diesel generators to be operable in each unit during operational modes 1, 2, and 3 (unitized). It does not identify the minimum number of diesels to be operable from the opposite unit in accordance with 10 CFR 50.36(c)(2)(i) to meet design basis safety functions of systems that are shared between two units. Please explain how the RICT calculations considered minimum required diesel generators as discussed in UFSAR Sections 3.1, 8.1.5.2, 8.3.1.1.3 and Required Actions of each unit. Please provide appropriate clarifications and TS markup, if required to comply with 50.36(c)(2)(i) requirements.

Response

The ESW and RHRSW systems common equipment and unitized power supplies are modeled in the PRA by including the required power supplies regardless of the unit designation of the power supply. For example, the ESW system has four pumps, A through D. The A and B pumps are powered by Unit 1, Division 1 and 2 4KV buses and associated EDGs. The C and D ESW pumps are powered by the Unit 2, Division 3 and 4 4KV buses and associated EDGs. In each unit specific PRA model, the four buses and EDGs (two from Unit 1 and two from Unit 2) are included explicitly in the PRA model for the ESW pumps. The basic event naming is consistent between both unit models. When one of these buses or EDGs is removed from service, the impact is evaluated for both units online risk and RICT calculations.

For ESW and RHRSW, in the plant system section (3/4.7) of the Technical Specifications, the pairing of pumps and associated diesel generators is explicitly addressed using the concept of a pump-diesel pair (TS 3.7.1.1.a.5, 6, and 7, and 3.7.1.2.a.4 and 5). This associates the pump and diesel regardless of the unit source of the diesel. For those Completion Times included in the scope of the RICT program, the minimum number of diesels required for these systems is addressed by the RICT Program, the Technical Specifications and the PRA models.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 33 of 42 Docket Nos. 50-352 and 50-353 The Control Enclosure Cooling Water (CECW) system (identified as the CSCWS in the RAI), and control room ventilation are not included in the scope of the RICT program. However, they are addressed under the Action statement in TS Section 3.8.1.1.e regarding two-train systems.

The SGTS also falls under the TS Section 3.8.1.1.e two-train Action statement. In addition, for Unit 2, the SGTS Technical Specifications explicitly address the inoperability of the Unit 1 diesels for the common SGTS system (Unit 2 TS 3.6.5.3.a.1, 3, and 4) and the Unit 2 Control Room Emergency Fresh Air System (CREFAS) TS addresses inoperability of the Unit 1 diesel power supplies (Unit 2 TS 3.7.2.a.1, 3, and 4). Note that the CREFAS TS was not included in the TSTF-505 LAR and the SGTS TS are being removed in response to the APLA RAI-10 and STSB RAI-1.

D. INSTRUMENTATION AND CONTROLS BRANCH (EICB) RAIS EICB RAI-1 The LAR is a risk-informed request to modify Limerick, Units 1 and 2 Technical Specification consistent with the approach approved in TSFT-505 Revision 2.

In Section 3.1.2.3 Evaluation of Instrumentation and Control Systems of the TSTF505 Revision 2 Model Application, the NRC clarifies the basis of the staffs safety evaluation is to consider a number of potential plant conditions allowed by the new TSs and to consider what redundant or diverse means were available to assist the licensee in responding to various plant conditions. The TSTF-505 Revision 2 position it that at least one redundant or diverse means (e.g., other automatic features or manual action) to accomplish the safety functions (e.g.,

reactor trip, safety injection, or containment isolation) remain available during the use of the RICT. This approach is consistent with maintaining a sufficient level of defense-in-depth in accordance with Regulatory Guide (RG) 1.174, Revision 2, An Approach for Using Probabilistic Risk Assessment in Risk Informed Decisions on Plant Specific Changes to the Licensing Basis, May 2011 (ADAMS Accession No. ML100910006), and the guidance in Revision 1 of RG 1.177, An Approach for Plant Specific, Risk Informed Decision making: Technical Specifications, May 2011 (ADAMS Accession No. ML100910008), which further describe the regulatory position with respect to defense-in-depth (including diversity). of the LAR list the FUNCTIONAL UNITs of the Instrumentation and Control Systems; however, this list does not provide NRC staff adequate information to verify at least one redundant or diverse means will remain available to accomplish the intended safety functions of I&C TS with RICT.

Please describe other means that exist to initiate the safety function for each plant accident condition that the identified TS 3/4.3 function is currently designed to address. The evaluation of diverse means, should identify the conditions that the FUNCTIONAL UNIT responds to, and for each condition, other means (e.g., diversity, redundancy, or operator actions) that can be used. Alternatively, provide additional information to demonstrate that defense in depth is maintained during the extended completion times for each function. This information is needed to demonstrate compliance with 10 CFR 50.36(c), and consistent with the implementing guidance in RG 1.174 and the TSTF-505 Revision 2.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 34 of 42 Docket Nos. 50-352 and 50-353

Response

The redundancy and diversity instrumentation information, for each applicable design basis accident or transient, is provided in Attachment 3 to show the appropriate level of defense in depth as requested.

EICB RAI-2 The TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b" (ADAMS Accession No. ML18183A493) excludes loss of function conditions (e.g.

trip capability is not maintained) from the risk informed completion time program. In particular, Note 1 in Table 1 specifies that some Conditions are applicable when an unspecified number of subsystems or instrument channels are inoperable, typically written as "One or more" or "Two or more". These conditions currently apply when all subsystems or channels required to be operable to perform a function are inoperable, and application of a RICT in this situation is prohibited.

The licensee inserted footnotes

• and *** to selected Conditions in this LAR (such as LCO 3.3.4.1.b) that states Not applicable when trip capability is not maintained. However, other Conditions in this LAR and, in which it is possible not to maintain trip capabilities in certain RICT configurations, do not have this footnote. For example, FUNCTIONAL UNIT 3 in Table 3.3.1-1, under LCO 3.3.1 Condition a, the TRIP UNIT A and C could be both inoperable (see Figure 7.2-3 in Limerick UFSAR). This would cause TRIP SYSTEM A inoperable, which would be a loss of function of FUNCTIONAL UNIT 3. Therefore, it appears that under some conditions, certain plant I&C configurations could include loss of function.

Please confirm that all conditions, in which trip capability in not maintained, are excluded from the application of the proposed RICT program for LCO 3.3.1, LCO 3.3.2, LCO 3.3.3, LCO 3.3.4.1, LCO 3.3.4.2 and LCO 3.3.9 for Limerick Generating Station, Units 1 and 2. This information is needed to demonstrate compliance with 10 CFR 50.36(c), and consistent with the implementing guidance in RG 1.174 and the TSTF-505 Revision 2 model SE.

Response

The instrumentation LCOs specified above have been reviewed for applicability of a RICT. The TS markups for the LCOs have been modified, as appropriate, to reflect that a RICT is not applicable if the trip capability is not maintained. A description of the changes for each TS, if any, is provided below.

LCO 3.3.1 - Reactor Protection System Instrumentation

• Added the footnote ***Not applicable when trip capability is not maintained for one or more Functional Units to TS Actions 3.3.1.a and 3.3.1.b.

LCO 3.3.2- Isolation Actuation Instrumentation

• Added the footnote ***Not applicable when trip capability is not maintained to TS Actions 3.3.2.b.1, 3.3.2.b.2.a, and 3.3.2.b.2.b.

• Added the footnote ***Not applicable for Function 7, Secondary Containment Isolation to TS Actions 3.3.2.b.1, 3.3.2.b.2.a, and 3.3.2.b.2.b.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 35 of 42 Docket Nos. 50-352 and 50-353 LCO 3.3.3 - Emergency Core Cooling System Actuation Instrumentation

• No change to TS Action 3.3.3.c.1 or 3.3.3.c.2. The logic for the ADS function is two-out-of-two twice. TS Action 3.3.3.c is for either ADS trip system subsystem inoperable, in which case, for this logic configuration, the other ADS trip system subsystem is operable and able to perform the function.

• For TS Table 3.3.3-1 Action Statements, added the footnote ***Not applicable when trip capability is not maintained to Actions 33 and 35. Actions 30.a and 34.a are good as previously submitted since they apply to only one channel inoperable.

LCO 3.3.4.1 - Recirculation Pump Trip Actuation Instrumentation

• Removed the footnote ***Not applicable when trip capability is not maintained from TS Action 3.3.4.1.c.1. The logic for the recirculation pump trip function is two-out-of-two twice.

TS Action 3.3.4.1.c is for the number of operable channels less than required for one trip system, in which case, for this logic configuration, the other trip system is operable and able to perform the function.

LCO 3.3.4.2 - End-of-Cycle Recirculation Pump Trip System Instrumentation

• Removed the footnote ***Not applicable when trip capability is not maintained from TS Action 3.3.4.2.c.1. The logic for the recirculation pump trip function is two-out-of-two twice.

TS Action 3.3.4.2.c is for the number of operable channels less than required for one trip system, in which case, for this logic configuration, the other trip system is operable and able to perform the function.

LCO 3.3.5 - Reactor Core Isolation Cooling System Instrumentation

• For TS Table 3.3.5-1 Action Statements, added the footnote ***Not applicable when trip capability is not maintained to Action 52. Action 50 stands as previously submitted since it applies to only one channel inoperable.

LCO 3.3.9 - Feedwater/Main Turbine Trip System Actuation Instrumentation

• No change to TS Action 3.3.9.b. This Action involves the number of operable channels one less than required. Therefore, as previously submitted, a footnote is not required to be applied to this Action.

• No change to TS Action 3.3.9.c. This Action involves the number of operable channels two less than required. As previously submitted, the footnote ***Not applicable when trip capability is not maintained is applied to this TS Action.

The above changes are reflected in the revised TS markups provided in Attachment 2.

E. TECHNICAL SPECIFICATIONS BRANCH (STSB) RAIS STSB RAI-1 TSTF-505, Revision 22, does not allow for TS loss of function conditions (i.e., those conditions that represent a loss of a specified safety function or inoperability of all required trains of a system required to be operable) in the risk informed completion time program.

2 ADAMS accession number ML18183A493

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 36 of 42 Docket Nos. 50-352 and 50-353 Based on the design success criteria provided in the license amendment request Table E1-1 it appears that some LCO actions may constitute a loss of function.

A. Provide a technical basis for why the actions that follow do not constitute a loss of function, or alternatively, remove them from the scope of the risk informed completion time program.

1. LCO 3.1.5, Standby Liquid Control System Action a: With only one pump and corresponding explosive valve operable

Response

LCO 3.1.5.1, Action a. does not constitute a loss of function. UFSAR Section 9.3.5 describes the basis for why only one SLC pump is required to meet the systems design basis safety function.

The SLC System is a backup reactivity control system and a post-accident water pH chemical control system to minimize iodine releases from primary containment.

These functions are accomplished by pumping a prescribed flow rate of sodium pentaborate solution (neutron absorbing poison) into the reactor vessel. The SLC system design and licensing bases has evolved over time. SLC has three distinct functions. Two are design basis functions. The remaining function demonstrates compliance to the requirements of the Anticipated Transient Without Scram (ATWS)

Rule (10CFR50.62) which is a beyond design basis special event as described in UFSAR Chapter 15.8 and UFSAR Sections 15.9.2.2.1 and 15.9.3.3.5. The three functions and their design criteria are as follows:

1. Original design basis backup capability for reactivity control independent of control rods. (UFSAR 9.3.5)

a. Number of pumps: 1

b. Minimum flow: No flow rate specified for system, pump flow rate minimum 37 gpm specified in Technical Specification 4.1.5.c.

2. Alternate source term (AST) Suppression Pool pH control during Design Basis Loss of Coolant Accident (LOCA) (UFSAR 9.3.5)

a. Number of pumps: 1

b. Minimum flow: 1600 gallons within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> (less than 6 gpm). The procedural guidance of SE-10 provides for up to 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> for this function to be accomplished. This results in a SLC system flow rate well below the nominal flow rate of one pump.

3. ATWS (10CFR50.62) Special Event (UFSAR 15.8)

a. Number of pumps: 2

b. Minimum flow: Equivalent of 86 gpm of 13 weight percent sodium pentaborate

2. LCO 3.5.1, ECCS - Operating Action d.1: With one of the above required ADS valves inoperable, provided the HPCI system, the CSS and the LPCI system are operable

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 37 of 42 Docket Nos. 50-352 and 50-353

Response

LCO 3.5.1.d.1 does not constitute a loss of function with four operable ADS valves.

Two operable ADS valves is the minimum valve complement for accident mitigation using the generic analysis in both NEDO-24708A (Reference STSB RAI-1.1) and NEDC-30936P (Reference STSB RAI-1.2) as described in UFSAR Chapter 6.3. The 10CFR50.46 ECCS LOCA analysis also supports that a complement of four operable ADS valves does not create a loss of function as documented in UFSAR Table 6.3-3.

The generic analysis of design basis accident (DBA) suction line breaks in both NEDO-24708A and NEDC-30936P forms the basis of certain Limerick ECCS TS limiting conditions for operation as described in UFSAR Chapter 6.3 (Section 6.3.1.1.2 o.). These Limerick applicable generic analyses require either one LPCI subsystem or one Core Spray System and two ADS valves during a small and intermediate LOCA to provide adequate core flooding/cooling and preclude fuel damage. ADS is not required for large break LOCA mitigation.

NEDC-30936P, Parts 1 and 2, were generically approved by NRC Safety Evaluation dated December 9, 1988 (Reference STSB RAI-1.2). NEDC-30936 was approved for use at Limerick and incorporated into the Limerick licensing basis by Amendment Nos. 53 and 17 for Limerick, Units 1 and 2, respectively, dated December 2, 1991 (Reference STSB RAI-1.3). The NEDO-24708A ECCS success criterion was also utilized in the 1982 Limerick Probabilistic Risk Assessment (PRA). NUREG/CR-3028 (Reference STSB RAI-1.4), dated February 1983, documents the Limerick PRA NRC review.

LCO 3.5.1.d.1 exceeds these minimum required ADS valves capability by requiring four operable ADS valves. Therefore, this LCO permits continued plant operation with this complement of high pressure ECCS equipment operable due to loss of redundancy, but not due to loss of function.

The 10CFR50.46 ECCS LOCA analysis also supports that LCO 3.5.1.d.1 does not create a loss of function, but never performed a specific minimum required valve complement evaluation. A complement of four operable ADS was evaluated in the 10CFR50.46 ECCS LOCA analysis as one of the many postulated ECCS single failure combinations as documented in UFSAR Table 6.3-3. However, it is not the limiting single failure since HPCI (ADS designed ECCS backup system) remains operable. The Limerick NRC Safety Evaluation Report (NUREG-0991) and Chapter 6.3 of the UFSAR have always identified that the loss of the Division II DC batteries as the limiting single failure. This failure causes HPCI, one RHR loop (B) and one core spray loop (B) to become inoperative.

3. LCO 3.6.1.3, Primary Containment Air Lock Action b: With the primary containment air lock inoperable, except as a result of an inoperable air lock door

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 38 of 42 Docket Nos. 50-352 and 50-353

Response

Upon further evaluation, it has been concluded that TS 3.6.1.3, Action b represents a loss of function condition. As a result, application of a RICT is removed from this TS.

This change is reflected in the revised TS markups provided in Attachment 2.

4. LCO 3.6.5.3, Standby Gas Treatment System - Common System (Unit 2)

Action a.3: With one standby gas treatment subsystem inoperable and the other standby gas treatment subsystem with an inoperable Unit 1 diesel generator Action a.4: With the Unit 1 diesel generators for both standby gas treatment system subsystems inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />

Response

The SGTS is being removed from the scope of the RICT Program as noted in the response to APLA RAI-10. Therefore, a RICT is no longer applicable to the LCO 3.6.5.3 Actions noted above. These changes are reflected in the revised TS markups provided in Attachment 2.

5. LCO 3.7.1.1, Residual Heat Removal Service Water System [RHRSW] -

Common System Action a.6: With three RHRSW pump/diesel generator pairs* inoperable

Response

Upon further evaluation, it has been concluded that TS 3.7.1.1, Action a.6 represents a loss of function condition. As a result, application of a RICT is removed from this TS. This change is reflected in the revised TS markups provided in Attachment 2.

6. LCO 3.7.1.2, Emergency Service Water System - Common System Action a.3: With one emergency service water system loop otherwise inoperable

Response

LCO 3.7.1.2.a.3 does not constitute a loss of function. As described in UFSAR Section 9.2.2, only one operable ESW loop and one operable ESW pump is required for accident mitigation on one unit and safe shutdown of the other unit. This LCO permits continued plant operation for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with only one ESW loop due to loss of redundancy, but not due to loss of function.

The ESW system is a Technical Specification support system that is designed to supply cooling water to equipment that supports safe reactor shutdown following a Design Basis Accident (DBA) or transient. Safety-related equipment cooled by ESW includes: RHR pump motors, pump compartment unit coolers for RHR, RCIC, HPCI, and Core Spray, the Control Room Chiller condenser, and standby Emergency Diesel Generator (EDG) heat exchangers. The HPCI and RCIC systems operability does not require pump compartment unit coolers for operability. The essential heat loads are automatically transferred from the non-safety related service water system to the ESW system under accident conditions or any time an EDG operates. The

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 39 of 42 Docket Nos. 50-352 and 50-353 ESW pumps start automatically after a time delay on emergency diesel generator (EDG) operation.

The ESW System is common to Units 1 and 2. It consists of two independent and redundant piping subsystems or loops (A and B) with two 100 percent system capacity ESW pumps per loop. For the A ESW loop, the A ESW pump is powered by the unit 1 A division EDG (D11) and the C ESW pump is powered by the unit 2 C division EDG (D23). For the B ESW loop, the B ESW pump is powered by the unit 1 B division EDG (D12) and the D RHRSW pump is powered by the unit 2D division EDG (D24). Each loop is capable of providing the required cooling capacity for reactor safe shutdown for both units as described in UFSAR Section 9.2.2. The two loops are separated so that a failure in one loop will not affect the function of the other loop.

A single operable loop of ESW system with a single operable ESW pump can support two divisions of equipment [(A & C) or (B & D)] per unit by providing the necessary cooling water for equipment operation that supports the ECCS, EDG and reactor decay heat/containment cooling function of RHR by providing the necessary cooling water to this equipment. The documented UFSAR basis that supports that the cooling furnished by a single ESW loop is sufficient to safely shut down both units are documented in:

1. UFSAR Chapter 6.3 for the minimum required complement of ECCS equipment using the realistic analyses presented in NEDO-24708A and NEDC-30936P during plant. These Limerick applicable generic analyses require either one LPCI subsystem or one Core Spray System to provide adequate core flooding/cooling and preclude fuel damage. A single loop of ESW provides the necessary cooling water to support this complement of equipment. Using the A ESW loop for example, the following operable ECCS equipment is available to respond to a DBA suction break LOCA per unit; HPCI, Core Spray loop A, LPCI loops A and C, ADS and EDG D11/D13 and D21/23. It is not based on the ECCS single failure evaluation results listed in UFSAR section 6.3 Table 6.3-3.

2. UFSAR Chapters 5.4.7 and 6.2 for the minimum required complement of equipment need for reactor decay heat and containment heat removal. These UFSAR sections describe that one operable RHR heat exchanger is adequate in the accident unit for accident mitigation and one RHR heat exchanger is adequate for decay heat removal in the safe shutdown unit. Four RHR pumps (2 per unit) cooled by the A ESW loop will be available.

3. The original issuance of the Limerick Unit 2 Technical Specifications (NUREG-1360), Electrical Power Systems TS 3/4.8 Bases that states: At least two onsite A.C. and their corresponding D.C. power sources and distribution systems providing power for at least two ECCS divisions (1 Core Spray loop, 1 LPCI pump and 1 RHR pump in suppression pool cooling) are required for design basis accident mitigation as discussed in UFSAR Table 6.3-3. Using the A ESW example; A core spray loop requires D11/D13, one LPCI loop requires D13, and one RHR in pool cooling requires D11 which are all cooled by water provided by the one ESW loop.

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 40 of 42 Docket Nos. 50-352 and 50-353 Therefore, for ECCS, RHR containment cooling, secondary containment, and control room habitability accident mitigation functions, only one loop of ESW does not constitute a loss of function.

ECCS in conjunction with primary and secondary containment are the accident mitigation features to limit the postulated release of radioactive material to the environment following a DBA (complete recirculation line suction break) LOCA as described in the UFSAR. Main control room habitability (CREFAS) is also required following the DBA LOCA (GDC 19).

As documented in UFSAR Sections 6.3 and 15.6.5 it is analytically demonstrated that no fuel damage occurs in either the realistic analysis (Section 6.3) or the 10CFR50.46 DBA accident analysis (15.6.5) when the proper complement of ECCS is operable which is supported by a single ESW loop. However, as part of the committed licensing basis, fuel damage is postulated to occur as described in UFAR section 15.6. This forms the committed basis for requiring an operable primary and secondary containment although no fuel cladding breaches that release radioactive material is predicted.

Primary containments accident mitigation function is to isolate and contain postulated fission products released from the reactor coolant system following a DBA LOCA and to confine the postulated release of radioactive material as described in UFSAR Chapter 6.2.

For primary containment integrity, a single operable ESW loop is acceptable with the exception of the HPCI and RCIC system steam supply and turbine exhaust line vacuum breaker primary containment isolation valves (PCIVs). For these systems, the normally open AC motor operated PCIVs automatically close on low steam pressure when their specific safety function is completed for primary containment isolation. For only these penetrations, primary containment integrity requires the proper combination of three operable EDGs. Either EDGs A and C, or B and D, and any other diesel generator would be required to mitigate the consequences of a DBA LOCA-LOOP.

However, the two EDGs per unit that would not be provided cooling water from the inoperable ESW loop can still automatically start, fully load, and function for approximately nine minutes prior to achieving the automatic high jacket water temperature trip setpoint without any cooling water. This is documented in the Fairbanks Morse Engineering Report, Service Water Shutoff Test No. 10 560 885, dated April 26, 1991 (Reference STSB RAI-1.5), that operated an EDG at full load to determine a conservative maximum allowable operating time without service water.

This time duration provides ample operating time for the HPCI/RCIC penetrations to automatically isolate on the accident unit.

As documented in the timeline contained in UFSAR Table 6.3.2 referenced in UFSAR Section 15.6.5 and the Limerick LOCA analysis of record in NEDC-32170P (Reference STSB RAI-1.6), reactor vessel pressure drops below the low steam pressure setpoint in approximately 60 seconds during the DBA-LOCA where fuel damage is postulated. At this point, these valves will receive an automatic closure signal on low steam line pressure and isolate these containment penetrations within

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 41 of 42 Docket Nos. 50-352 and 50-353 two minutes post-accident. Therefore, for primary containment integrity, one loop of ESW will not result in a loss of function.

For a discussion of one ESW loop inoperable during RHRSW piping repairs, see the response to EEOB RAI-01.

Action a.4: With three ESW pump/diesel generator pairs** inoperable

Response

Upon further evaluation, it has been concluded that TS 3.7.1.2, Action a.4 represents a loss of function condition. As a result, application of a RICT is removed from this TS. This change is reflected in the revised TS markups provided in Attachment 2.

References STSB RAI-1.1 Limerick UFSAR, Revision 19, Reference 6.3-3, General Electric Company, "Additional Information Required for NRC Staff Generic Report on Boiling Water Reactors," NEDO-24708A, Revision 1, (December 1980).

STSB RAI-1.2 Limerick UFSAR, Revision 19, Reference 6.3-4, General Electric Company, "BWR Owner's Group Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Activation Instrumentation)," NEDC-30936P-A, (December 1988).

STSB RAI-1.3 Letter from R. Clark (USNRC) to G. Beck ((Philadelphia Electric Company), Reduced Testing of RPS, ECCS and Common Instrumentation, Change Request 89-16, Limerick Generating Station, Units 1 and 2 (TAC Nos. 76689 and 76690), dated December 2, 1991 (ADAMS Accession No. ML011550525).

STSB RAI-1.4 Papazoglou, I. A., et al., "A Review of the Limerick Generating Station Probabilistic Risk Assessment," Brookhaven National Laboratory, NUREG/CR-3028, February 1983.

STSB RAI-1.5 Fairbanks Morse Engineering Report, Service Water Shutoff Test No. 10 560 885, dated April 26, 1991.

STSB RAI-1.6 Limerick UFSAR, Revision 19, Reference 6.3-6, GE Nuclear Energy, Limerick Generating Station, Units 1 and 2, SAFER/GESTR-LOCA, Rev. 2, Loss-of-Coolant Accident Analysis, NEDC-32170P, Rev. 2, May 1995.

B. There appears to be a discrepancy between the design success criteria column in license amendment request Table E1-1 and the design as described in the updated final safety analysis report for LGS. Update Table E1-1 design success criteria to be consistent with the updated final safety analysis report or explain why the design success criteria discrepancy exists for the following systems:

Response to Request for Additional Information Attachment 1 LAR to Adopt TSTF-505, Rev. 2 Page 42 of 42 Docket Nos. 50-352 and 50-353

1. LCO 3.6.2.2, Suppression Pool Spray

2. LCO 3.6.4.1, Suppression Chamber - Drywell Vacuum Breakers

Response

Table E1-1 design success criteria has been updated consistent with the UFSAR. See attached Enclosure1.

GENERAL REFERENCES

1. Letter from J. Barstow (Exelon Generation Company, LLC) to U.S. Nuclear Regulatory Commission, License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b'," dated December 13, 2018 (ADAMS Accession No. ML18347B366).

2. Letter from D. Helker (Exelon Generation Company, LLC) to U.S. Nuclear Regulatory Commission, Supplement to License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b," dated February 14, 2019 (ADAMS Accession No. ML19045A011).

3. Electronic mail message from V. Sreenivas, U.S. Nuclear Regulatory Commission, to G.

Stewart, Exelon Generation Company, LLC, "Limerick-Request for Additional Information:

Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Completion Times -RITSTF Initiative 4b (EPID L-2018-LLA-0567)," dated July 10, 2019 (ADAMS Accession No. ML19192A031).

ATTACHMENT 2 License Amendment Request Limerick Generating Station, Units 1 and 2 Docket Nos. 50-352 and 50-353 Response to Request for Additional Information License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b."

Proposed Technical Specification Changes (Revised Markups)

TS Pages (Units 1 and 2) 3/4 1-19 3/4 5-2 3/4 7-9 3/4 3-1 3/4 5-3 3/4 7-33 3/4 3-9 3/4 6-5 3/4 8-1 3/4 3-32 3/4 6-15 3/4 8-1a 3/4 3-36 3/4 6-16 3/4 8-2 3/4 3-42 3/4 6-17 3/4 8-2a 3/4 3-46 3/4 6-44 3/4 8-10 3/4 3-54 3/4 7-1 3/4 8-10a 3/4 3-112 3/4 7-1a 3/4 8-17 3/4 4-23 3/4 7-3 6-14e

REACIIVIIY CONTROL SYSIEMS 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM I IMITING CONpITION FOR OPERATION 3.1.5 The standby liquid control system shall be OPERABLE and consist of the following:

a. In OPERATIONAL CONDITIONS 1 and 2, two pumps and corresponding flow paths,

b. In OPERATIONAL CONDITION 3, a minimum of one ump and corresponding flow path. * / - ~

<.:71-' 1n' ~CCI? r O'A 'JC(:_. t-<Jnc APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, The ~./.sk .:z:;?yt;,,./lt.ed' ACTION: Le'MN;::>/e-n'(:JrJ 7/'"ae ~~nt"h ~

a. With only one pump and corresponding explosive valve OPERABLE, in OPERATIONAL CONDITION 1 or 2, restore one inoperable pump and corresponding explosive valve to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

b. With standby liquid control system otherwise inoperable, in OPERATIONAL CONDITION l, 2, or 3, restore the system to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILIANCE REOlllREMENIS 4.1.5 The standby liquid control system shall be demonstrated OPERABLE:

a. In accordance with the Surveillance Frequency Control Program by verifying that:

1. The temperature of the sodium pentaborate solution is within the limits of Figure 3.1.5-1.

2. The available volume of sodium pentaborate solution is at least 3160 ga 11 ans.

3. The temperature of the pump suction piping is within the limits of Figure 3.1.5-1 for the most recent concentration analys i s .

'--. __ )

LIMERICK - UNIT 1 3/4 1-19 Amendment No. ~.9-6,&7,~.~. 201

3/4.3 INSTRUMENTATION 3/4~3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the reactor protection system instrumentation channels shown in Table 3.3.1-1 shall be OPERABLE with the REACTOR PROTECTION SYSTEM RESPONSE TIME as shown in Table 3.3.1-2. ' ,,,.. ;"' ~,..c/a..~c...c e.v;-f~ ~

APPLICABILITY: As shown in Table 3.3.1-1. ~JJ-_p,/,~/ U,"r/e/,.;,>r ACTION: . . /,,nt:- f?-11.Jr~,-*'*~

Note: Separate condition entry is allowed for each channel.

Note: When Functional Unit 2.b and 2.c channels are inoperable due to the calculated power exceeding the APRM output by more than 2% of RATED THERMAL POWER while operating at ~ 25% of RATED THERMAL POWER, entry into the associated Actions may be delayed up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

a. With the number of OPERABLE channels in either trip system for one or more Functional Units less than the Minimum OPERABLE Channels per Trip System required by Table 3.3.1-1, within one hour or eac a ec e unc ona unit either verify that at least one* channel in each trip system is OPERABLE or tripped or that the trip system is tripped, or place either the affected trip system or at least one inoperable channel in the affected trip system in the tripped condition.

b. With the number of OPERABLE channels in either trip system less than the Minimum OPERABLE Channels per Trip System required by Table 3.3.1-1, place either the inoperable channel(s) or the affected trip system** in the tripped conditions within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />

c. With the number of OPERABLE channels in both trip systems for one or more Functional Units less than the Minimum OPERABLE Channels per Trip System required by Table 3.3.1-1, place either the inoperable channel(s) in one trip system or one trip system in the tripped condition within 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s* .

d. li within the allowable time allocated by Actions a, b or c, it is not desired to place the inoperable channel or trip system in trip (e.g., full scram would occur),~ no later than expiration of that allowable time initiate the action identified in Table 3.3.1-1 for the applicable Functional Unit.

• For Functional Units 2.a, 2.b, 2.c, 2.d, and 2.f, at least two channels shall be OPERABLE or tripped. For Functional Unit 5, both trip systems shall have each channel associated with the MSIVs in three main steam lines (not necessarily the same main steam lines for both trip systems) OPERABLE or tripped. For Function 9, at least three channels per trip system shall be OPERABLE or tripped.

• • For Functional Units 2.a, 2.b, 2.c, 2.d, and 2.f, inoperable channels shall be placed in the tripped condition to comply with Action b. Action c does not apply for hese Function Uni ts.

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-1 Amendment No. ftd-, 7.+-, 141-, 1-7-7-, 2QQ, 219, 233 I

I~STRUMENTATION

-,) 3/4.3.2. ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2.-2 and with ISOLATION SYSTEM RESPONSE TIME as snown in Table 3.3.2-3.

APPLICABILITY: As shown in Table 3.3.2-1 .

ACTION:

a) With an isolation actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.

b) With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per* Trip System requirements for one trip system:

1. If pla~ing the inoperable channel{s) in the tripped condition would cause an isolation, he inoperable channel(s) shall be restored to OPERABLE status within 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> . If this cannot be accomplished, the ACTION required by Table

. . or e affected trip . function shall be taken, or the channel shall be placed in the tripped condition.

or

.. ) 2. If pl~cing the inoperable channel{s) in the tripped condition would not cause an isolation, the inoperable channel(s) and/or that trip system shall be placed in the tripped condition within:

a) 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for trip functions common* to RPS Instrumentation.

b) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for trip functions not common* to RPS Instrumentation.

",_ /n e11-CCPrclance "",".f), ~e ~.sJ- .:Z-n/,r,,,,_ej C~,.Pl~~n /ine.e fi-l:f}rf)..>H~

• Trip functions common to RPS Actuation Instrumentation are shown i n Tab 1e 4. 3. 2 .1-1. --- ---:--- - --;-,,___- J

~ '* Nf,f CA.ff /;ca..Jfe:- whe;. ,7-,jo cr4',A~ ;$ , , , /~,,/...,".,,.e.J.

H- Aft:,./- o/'l'/,*~Je -h,, P(;Vlcf/~n ~ Sf!C4'1d"1t-7 ~,,jtU,,At8

.....::;z::$o-/a..-./it:J /h-LIMERICK UNIT 1 3/4 3-9 Amendment No . .&J, 6-fl, 169

INSTRUMENTATION 3/4.3 .3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION

.WMITING CONDITION FOR OPWTION 3.3.3 The emergency core cooling system <ECCS) actuation instrumenta channels shown in Table 3.3.3- 1 shall be OPERABLE with their trip tion set consi stent with the values shown in the Trip Setpoint column setpo ints and with EMERGENCY CORE COOLING SYSTEM RESPONSE TIME as shown in of Table 3.3.3-2 Table 3.3.3- 3.

APPLICABILITY: As shown in Table 3.3.3- 1 ACTION:

a. With an ECCS actuat ion instrumentation channel trip setpo int less conservative than the value shown in the Allowable Values column Table 3.3.3- 2, declar e the channel inoperable until the channe of restor ed to Operable status with its trip setpo int adjusted consi l is with the Trip Setpo int value. stent

b. With one or more ECCS actuat ion instrumentation channels inoperable, take the ACTION required by Table 3.3.3 -1.

c. With either ADS trip system subsystem inoperable, restor e the inoperable trip system to OPERABLE status within:

1. 7 days, provided that the HPCI and RCIC systems are OPERABLE.

---

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2, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />  ::t:'h.4nn.cd' CP.e/'/e:-1".;~ r;*Aee... /r"Jrd.,,,.,,_

Otherwise, be in at least HOT SHUTDOWN within the next 12 ours and reduce reacto r steam dome pressure to less than or equal to 100 psig within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

~RVEILLANCE REOUIREM[NTS 4.3.3 .l Each ECCS actuat ion instrumentation channel shall be demon OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTI strated CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS shown ONAL TEST and 4.3.3. 1-1 and at the frequencies specif ied in the Surve illanc e in Table Program unless otherwise noted in Table 4.3.3. 1-1. Freque ncy Control 4.3.3. 2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operat all channels shall be performed in accordance with the Surve illanc ion of Control Program. e Frequency 4.3.3 . 3 The ECCS RESPONSE TIME of each ECCS trip function shown in shall be demonstrated to be within the limit in accordance with Table 3.3.3 -3 Frequency Control Program . Each test shall include at least one the Surve illanc e channe system such that all channels are tested at least once every N times l per trip frequency specif ied in the Surve illanc e Frequency Control Progra the total number of redundant channels in a specif ic ECCS trip system m where N is the I

/

LIMERICK - UN IT 1 3/4 3-32 Amendment No. +.J., 186

TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION STATEMENTS ACTION 30 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. With one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> r declare the associated system inoperable.

With more than one channel inoperable, declare the associated system inoperable.

ACTION 31 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, declare the associated ECCS inoperable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 32 - DELETED ACTION 33 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requiremen , restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the associated ECCS inoperable.

ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. For one channel inoperable, place he inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the HPCI system inoperable.

b. With more than one channel inoperable, declare the HPCI system inoperable.

With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the HPCI system inoperable.

With the number of OPERABLE channels less than the Total Number Channels, declare the associated emergency diesel generator and the associated offsite source breaker that is not supplying the bus inoperable and take the ACTION required by Specification 3.8.1.l or 3.8.1.2, as appropriate.

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UNIT 1 3/4 3-36 Amendment No . .J:.l., ~. ~. 227

INSTRUMENTATION 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION

(

ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION **--"'

LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram re~irculation pump trip CATWS-RPT) system instrumenta tion channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values show in the Trip Setpoint column of Table 3.3.4.1-2. _ . . ,.,.,,.,,,, . I - 11_ L.J_ '7',J

, ..,i1- 1111 ,.,_,.._,,rdanee e.v, 7'7 -r'U!. /C. ~sx:-

APP LI CAB I LI TY: OPERATIONAL CONDITION 1. ~,t;,...,,,J ~k.f,~ /,"nte ~ ~*

ACTION:

a. With an ATWS recirculatio n pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.1-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel trip setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by the.

Minimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel(s) in the tripped condition within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

c. With the number of OPERABLE channels two or more less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system and: (

\

\~

1. If the inoperable channels consist of one reactor vessel water level channel and one reactor vessel pressure channel, place both inoperable channels in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, or if this action will initiate a pump trip, declare the trip sys em i noperab 1e.

2. If the inoperable channels include two reactor vessel water level channels or two reactor vessel pressure channels, declare the trip system inoperable.

d.

e.

SURYEILLANCE REQUIREMENTS 4.3.4.1.1 Each of the.required ATWS recirculatio n pump trip system instrumenta tion channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillanc e Frequency Control Program.

4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simu.lated automatic operation of (~.

all channels shall be performed in accordance with the Surveillance Frequency Control Pro ram. - _}_ 1

~ N,.l-a..;-,,./~k ec;k,,, ;?--;p ~~,).:/-/ IS ADT nta.id~n-Cd.

LIMERICK - UNIT 1 3/4 3-42 Amendment No. -W, +l-, 186

INSTRUMENTATION END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION I IMITING CONQITION FOR OPERATION 3.3.4.2 The end-of-cycle recirculation pump trip CEOC-RPT) system instrumentation channels shown in Table 3.3.4.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.4.2-2 and with the END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME as.shown in Table 3.3.4.2 -3.

APPLICABILITY: OPERATIONAL CONDITION l, when THERMAL POWER is greater tha or equal to 29.5% of RATED THERMAL POWER. ~ 0 ,... ;,, A.C~4",-4"A>-t:.r ~-f), -{At!

ACTION: /:i_sk f>i-,l'e>,...hl-t:d C.,,.-.nl° /d,'bn 17m c. ;:;-~ rtUn. -H-

a. With an end-of-cycle recirculation pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel(s) in the tripped condition within 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />

c. With the number of OPERABLE channels two or more less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system and:

1. If the inoperable channels consist of one turbine control valve channel and one turbine stop valve channel, place both inoperable channels in the tripped condition within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

2. If the inoperable channels include two turbine control valve channels or two turbine stop valve channels, declare the trip system inoperable.

d. With one trip system inoperable, restore the inoperable trip system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or take the ACTION required by Specification 3.2.3.

e. With both trip systems inoperable, restore at least one trip system to OPERABLE status within one hour or take the ACTION required by Specification 3.2.3. 0 ,_

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LIMERICK - UNIT 1 3/4 3-46 Amendment No. +Q, 201

TABLE 3.3.5-1 (Continued)

REACTOR CORE ISOLATION COOLING SYSTEM ACTION STATEMENTS ACTION 50 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

.a. With* one channel inoperable. pl,ce the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> r declare the RCIC system inoperable.

b. With more than one channel inoperable, declare the RCIC system inoperable.

ACTIO~ 51 - With the number of OPERABLE channels less than required by the minimum OPERABLE channels per Trip System requirement, declare the RCIC system inoperable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 52 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement, place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the RCIC system inoperable.

~------"""

With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels ~er Trip System requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the RCIC system inoperable.

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LIMERICK - UNIT 1 3/4 3-54 Amendment No. 53 ni:-r t 'I 1111

INSTRUMENTATION 314. 3. 9 FEEDWATER/MAIN TURBINE TRIP* SYSTEM ACTUATION INSTRUMENTATION LIMITING CONOITIO_N FOR OPERATION 3.3.9 The feedwater/main turbine trip system actuation instrumen tation channels shown in the Table 3.3.9-1 shall be OPERABLE with their trip setpoints set consisten t with the values shown in the Trip Setpoint column of Table 3.3.9-2.

APPLICABILITY: As shown in Table 3.3.9-1. ~ ";"" i'1 ac~rc/ec..nCe "";/_4 -fAe..

ACTION: psK..: rnhr* 'ecl ~~/.d;~

/ht e- rF--t:drt:Ul't~ .

a. With a feedwater/main turbine trip system ac ua ion instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.9-2, declare the channel inoper-able and either place the inoperable channel in the tripped condition until the channel is restored to OPERABLE status with its trip set-point adjusted consisten t with the Trip Setpoint value, or declare the associated system inoperable.

b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels requirement, restore the inoperable channel to OPERABLE status within 7 days or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

c. With the number of OPERABLE channels two less than required by the Minimum OPERABLE Channels requirement, restore at least one of the inoperable channels to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

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4.3.9.1 Each of the required feedwater/main turbine trip system actuation instrumentation channels shall be demonstrated OPERABLE* by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillance Frequency Control Program.

4.3.9.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed in accordance with the Surveillance Frequency Control Program.

• A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required )

surveillan ce without placing the tri system in the tripped condition . ~~

~ /Vbl ~/,&~le- (...Olten ~io ~d~~/. ~ /"":5 nP,L-*~'",,.,7'-~4c_J.

LIMERICK - UNIT 1 3/4 3-112 Amendment No. :+IJ, ++/--, 186

REACTOR COOLANT SYSTEM

~')114.4.7 MAIN STEAM LINE ISOLATION VALVES

_./

6IM1TING CONQITIQN EQR OPERATION 3.4.7 Two main steam line isol atio n valves be OPERABLE with clos ing times grea ter than CMSIVs) per main steam line shal l equal to S seconds. or equal to 3 and less than or APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION: <:Jr  ;>' ~c..o,...o/,a..,,c~e. w;-fJ. -f~ Bs:K With one or more MSIVs inop erab le: _:i:::;, r4> rJIH ~c:/ ~#f>/d, ~>1 7[;t,..-e. Prt'JJ ~

a. Maintain at leas t one MSIV OPERABLE in each affe cted main steam line that is open and with in 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> , eith er: I

1. Restore the inoperable valv e(s) to OPERABLE stat us, or

2. Isol ate the affected main steam line by use the clos ed posi tion . of a deactivated MSIV in

b. Otherwise, be in at leas t HOT SHUTDOWN SHUTDOWN with in the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> . within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD j

.SUB.Yf,JLLANCE RFOllI REMf]TS 4.4 .7 Each of the above requ ired MSIVs shal veri f ying full cl osure between 3 and 5 seconds l be demonstrated OPERABLE by Spe cific atio n 4.0. 5. when test ed pursuant to LIMERICK - UNIT 1 3/4 4-23 Amendment No. 169

EHERGENCY CORE COOLING SYSTEMS L MITING ONO TION FOR OPE I () . .

~ ,~ ~

ACTION; or ;n ~r--d'a..nc.e &AJ~*..,i-;, +. e

~;~f:. ..::z:;,,./lPr.l'Hed Une/'/eh~

a. For the core spray *system: --r7me.- ~t:>~r~::.

1. With one CSS subsystem inopera e, prov e* at at least two LPCI subsystems are OPERABLE, restore the ino erable CSS subs stem to OPERABLE status within 7 day or e 1n a eas S WN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COL SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. I

2. With both CSS subsystems inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. For the LPCI system:

1. With one LPCI subsystem inoperable, provided that at least one css*

subsystem is OPERABLE, restore the inoperable LPCI pump to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. With one RHR cross-tie valve (HV-51-182 A or B) open, or power not removed from one closed RHR cross-tie valve operator, close the open valve and/or remove power from the closed valves operator within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3. With no RHR cross-tie valves (HV-51-182 A, 8) closed, or power not removed from both closed RHR cross-tie valve operators, or with one RHR cross-tie valve open and power not removed from

)

the other RHR cross-tie valve operator, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. With two LPCI subsystems inoperable, provided that at least one CSS subsystem is OPERABLE, restore at least three LPCI subsystems to L status within 7 da s or be in at least HOT SHUTDOWN within the next 12 ours and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.I W~th three LPCI subsystems inoperable, provided that both CSS subsystems are OPERABLE, restor at least two LPCI subsystems to OPERABL status within 7 a s or be in at least HOT SHUTDOWN within e next 12 ours and in COLD.SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

With all four LPCI subsystems inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.*

~r /A ~a.HC-e ~,;t.h T.!e..

?;..sK- ..:z:n4r--mecl ~,Pleh"Pr.t 77~e..- #~~.,

• Whenever both shutdown cooling subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal method.s.

LIMERICK - UNIT l 3/4 5-2 Amendment No. 86, &4, 131

_NOV 1 6 1998

EMERGENCY CORE COOLING SYSTEMS LU1 lI ING CONDI UmL.E,.OR Q_f!.E.RAl::::;LO;;N...JJ::=;';::*o::n::tin:::'~u~.~===--===~==::.:::::=====

1'\CTION: (Continued) ~ /;i ~,..-c/a;ru;_ Lc.:.r; ~J, -rA.e ~:S k

..::z:;., hr~ C'e>Nyl)/e/; IP/J 77dee- ;9~,,..-a~.J For the HPCI system:

L With the HPCI system inoperable, provided the CSS, the LPCI system, the ADS and the RCIC system are OPERABLE, restore the llPCt system to OPERABLE status *.vithin 14 days or be in a east HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam Jome pressure to s 200 psig within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. With the HPCI system inoperable, ~nd one CSS subsystem, and/or LPCI subsystem inoperable, and provided at 1east one CSS subsystem, three LPCI subsystems, and ADS are o erable restore the HPCI to OPERABLE within 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> , or be in HOT SHUTDOWN in the nex 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and in COLD SHUTDOWN in the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3. Specification 3.0.4.b is not applicable to HPCI.

For the ADS:

1. With one of the above required ADS valves inoperable, provided the HPCI system, the CSS and the LPCI system are OPERABLE.

restore the inoperable ADS valve to OPERABLE status within

---

r"\1--rda-y-s""or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to s 100 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

• 2. With two or more of the above required ADS valves inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to s 100 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

e. With a CSS and/or LPCI header 6P instrumentation channel inoperable, restore the inoperable channel to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or determine the ECCS header ~P locally at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />; otherwise, declare the associated CSS and/or LPCI, as applicable, inoperable.

f. DELETED LIMERICK UNIT l 3/4 5-3 Amendment No. J:J., 94, ~. 211

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK LIMITING CONDITION FOR OPERATION 3.6.1.3 The primary containment air lock shall be OPERABLE with:

a. Both doors closed except when the air lock is being used for normal transit entry and exit through the cqntainment, then at least one air lock door shall be closed, and

b. An overall air lock leakage rate in accordance with the Primary Containment Leakage Rate Testing Program.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2*, and 3.

ACTION:

a. With one primary containment air lock door inoperable:

1. Maintain at least the OPERABLE air lock door closed and either restore the inoperable air lock door to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or lock the OPERABLE air lock door closed.

2. Operation may then continue until performance of the next required overall air lock leakage test provided that the OPERABLE air lock door is verified to be locked closed at least once per 31 days.

3. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With the primary containment air lock inoperable, except as a result of an inoperable air lock door, maintain at least one air lock door closed; restore the inoperable air lock to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Qr- in t:c..c.C6~&t.nc.e UJ.,-.;1 ~ ~k z/;rni,J C.o:>n?/' /e:/,;,,., / /'m-e. ~f~_j

• See Special Test Exception 3.10.1.

LIMERICK - UNIT 1 3/4 6-5 Amendment No. JJ, ~. 169

CONTAINMENT SYSTEMS SUPPRESSION POOL SPRAY

) Lt!'11IJNG CONDITION FOR OPERATION 3.6.2.2 The suppression pool spray mode of the residua l heat removal system shall be OPERABLE with two *independent loops, each loop consist ing (RHR) of:

a. One OPERABLE RHR pump, and

b. An OPERABLE flow path capable of recircu lating water from the suppres sion chamber through an RHR heat exchanger and the suppres sion pool spray sparger (s).

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

A_CTION: t/r ;n a.cc.orc/a..nce, "";-1.4 -rAe 4.sk

....::z:;,~y-;nc:-.,,/ Ce>.lll't; /d*./t::1n 7J'~e ffe>;Jrt:l-N-f-~

a. With one.suppression pool spray loop inoperable, restore the inoperable loop to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With both suppression pool spray loops inoperable, restore at least one loop to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN* within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILLANCE REO\JIREMEN .

4.6.2.2 The suppression pool spray mode of the RHR system shall be demonstrated OPERABLE:

a. In accordance with the Surveil lance Frequency Control Program by verifyi ng that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in positio n, is in its correct positio n.

b. By verifyi ng that each of the require d RHR pumps develops a flow of at least 500 gprn on recircu lation flow through the RHR heat exchanger and the suppression pool spray sparger when tested pursuant to Speci-ficatio n 4.0.5.

c. By verifyin g RHR suppression pool spray subsystem locatio ns suscep tible to gas accumulation are suffici ently filled with water in accordance with the Surveil lance Frequency Control Program.

• Whenever both RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as require d by this ACTION, maintain reactor coolant temperature as low as practic al by use of alterna te heat removal methods .

.,_)

LIMERICK - UNIT l 3/4 6-15 Amendment Mo. g{3.,-H-+/--,+@B., 216

CONTAINMENT SYSTEMS SUPPRESSION POOL COOLING LIMITING CONDITION FOR OPERATION 3.6.2. 3 The suppre ssion pool cooling mode of the residu al heat removal CRHR) system shall be OPERABLE with two independent loops, each loop consis ting of:

a. One OPERABLE RHR pump, and

b. An OPERABLE flow path capable of recircu lating water from the suppression chamber through an RHR heat exchanger.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, an.d 3. _ - /!

~,.... ;n ~ref~C.t:!! ~.rrh rle:. ,2?;J I:: _t:-nr-~rn<e ACTION:

~ /c=-~ '"ein ~e.-fi-P!/~ .!I>

a. With one suppression pool cooling loop inoperable, restore the inoperable loop to OPERABLE status within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s** or be in at leas W within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN witt1in the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With both suppression pool cooling loops inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN* within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SU RV EI LLANCE REO!JIREMENTS 4.6.2. 3 The suppre ssion pool cooling mode of the RHR system shall be demonstrated OPERABLE:

a. In accordance with the Survei llance Frequency Control Program by verify ing that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed , or otherwise secured in positio n, is in its correc t positio n.

b. By verifyi ng that each of the required RHR pumps develops a flow of at least 10,000 gpm on recircu lation flow through the flow path including the RHR heat exchanger and its associ ated closed bypass valve , the suppression pool and the full flow test line when tested pursuant to Specif ication 4.0.5.

c. By verify ing RHR suppression pool coolin g subsystem locatio ns suscep tible to gas accumulation are suffic iently filled with water in accordance with the Survei llance Frequency Control Program.

• Whenever both RHR subsystems are inoper able, if unable to attain COLD as require d by this ACTION, maintain reacto r coolan t temperature as lowSHUTDOWN practi cal by use of altern ate heat removal methods. as

• • Dur ing the extended~llowed Outage Time CAOT) specif ied by TS LCO 3.7.1. l, Action a.3.al or a.3 .b ) to allow for RHRSW subsystem piping repair s, the 72-hour AOT for one ~~bl e_s uppressi~n poo1 cooling loop ma also be extend,ed to 7 day for the same -: period.>o.,... 11-~ ~ a..ne-e ~;.f-h Tkc ,£,,..s£ - , '"\

...:znr:;n-neel &...u 1~7'*t:Jn 7/,n.t:- - ~ra.fl'-,:. ' ._,,)

LIMERICK - UNIT 1 3/4 6-16 1\mendment No. ra+,w,g.e.,N+,-J:.g.&,t-GJ, 215

CONTAINMENT SYSTEMS 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.3 Each primary containment isolatio n valve and each instrumentation line excess flow check valve shall be OPERABLE.

APPLICABILITY:

ACTION:

a. With one or more of the primary containment isolatio n valves inoperable,**

maintain at least one isolatio n valve OPERABLE in each affected penetra tion that is open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:

1. Restore the inoperable valve(s) to OPERABLE status, or

2. Isolate each affecte d penetration by use of at least one de~

activat ed automatic valve secured in the isolate d positio n,* or

3. Isolate each affecte d penetration by use of at least one closed manual valve or blind flange.*

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With one or more of the instrumentation line excess flow check valves inoperable, operation may continue and the provisions of Specification 3.0.3 are not applica ble provided that within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:

1. The inoperable valve is returned to OPERABLE status, or

2. The instrument line is isolated and the associated instrument is declared inoperable.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c. With one or more scram discharge volume vent or drain valves inoperable, perform the applicable actions specified in Specification 3.1.3.1 .

• Isolatio n valves closed to satisfy these requirements may be reopened on an interm ittent basis under administrative control .

• • Except for the scram discharge volume vent and drain valves.

LIMERICK - UNIT 1 3/4 6-17 Amendment No. ~ *.i49.~.~.192

CONTAINMENT SYSTEMS 3/4.6.4 VACUUM RELIEF

)

SUPPRESSION CHAJilER

• DRVWELL VACUUM.BRE AKERS LIMITING CDNOITIDN FOR OPERATION 3.6 .4. l Three pairs af suppression chil lllber

• drywal vac:u111 breakers shall OPERABLE and all suppressio n chamber - dT')'Wlll vacu\mll bre be akers shall be closed. \

APPLICABILITY: OPERATIONAL CONDITI ONS l

• and 3 .

ACTION: ~,,. . 1~ tJ..e.~rdNiC.41! '4-'.f~J ./.4e J?;.$

r;,~nt1tttd" Co.n?~ ~~..., 7?. we

a. With one or more v

• na ers 1n/e- ,P;-t!>.f~

suppression ch er

• drywe11 vacui11one o thr u re p but kno w to be closed, restore at lea breaker air s inoperzible for rsopeofning breakers to OPERABLE status vit hin 72 st a inopenble pai r of vacuum

'SHUTDOWN vithin t.nl nex hou n or be in at leu t HOT following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

• t l2 hou n and in LD SHUTDOWN within the

.b. With one S&rPIJ"SSion chlll.lllbo

• drywall the other vacum bT'Hker in rtbe vacuma b1"G1lcer open, ver ify res tor e the open vacum breaker pai r to be cla Hd within 2 havrs; ta the closed position within 72 hou or be in at lea st HOT SfWTDOWN wit hin the next 12 ho111"'S and in COLD rs SHUTDOWN vit Mn the following 24 hou rs.

c. With one position indicator of any sup vacuum breaker inoperable: pression chlllber

• dr,ywell

l. Ver ify the other vacuum bM ake r 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and at lea st once per 15indaythe pai r to be closed within s the rea fte r, or

2. Verify the vacuum breaker(s) with the indicator to be closed by conducting inoperable position that the 6P is maintained at a tes t which demonstrates gre ate for one hour without makeup t:rithin 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> than or equal to 0.7 psi rs and at lea st once per 15 days thereafter*

Oth erv iset be in t lea st HOT SHUT in COLD SHUTDOWN within the followDOW N within the next U hours and ing 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

LIMERICK - UNIT 1 3/4 6-44 Amendment Ho. 46 OCT OZ ~

3/4. 7 PLANT SYSTEMS 3/4. 7.1 SERVICE WAJER SYSTEMS RESIDUAL HEAT REMOVAL SERVICE WATER SYSTEM -

I IMIIING CONQUION COMMON SYSTEM FOR OPERATION

) 3.7. 1.1 At leas t the following (RHRSW) system subsystems, with eachinde pendent residual heat removal service water subsystem comprised of:

a. Two OPERABLE RHRSW pumps, and

b. An OPERABLE flow path capable of taking suct ion water pumps wet pits which are supplied from the RHR serv ice cooling tower basin and tran sfer ring the wate from the spray pond or the RHR heat exchanger, r throu gh one Unit 1 shal l be OPERABLE:

a. In OPERABLE CONDITIONS 1, 2, and 3, two subsystem s.

b. In OPERABLE CONDITIONS 4 and 5, the subsystem(s) systems and components required OPERABLE by Spec associated with 3.9. 11.l , and 3.9. 11.2 . ifica tion 3.4. 9.2.

APPLI~ABl I UY: OPERATIONAL CONDITIONS l, 2, 3, 4, and 5.

ACTION;

a. In OPERATIONAL CONDITION l, 2, or 3:

1. With one RHRSW pump inoperable, rest ore the inop

.' I OPERABLE statu s within 30 days, or be in at leas erable pump to within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN t HOT SHUTDOWN l

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. within the following W1th one RHRSW pump in each subsystem i nope

<"r in c;.a:orc/Mt:t! leas t one of the inoperable RHRSW pumps to OPER rable, rest ore at w1 1n ays or be in at leas t HOT ABLE statu s

(,1.N"f-h Y-k ;E'r.rk 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 1n COLO SHUTDOWN within SHUTD OWN within the next the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

~hrdiJ 3. With one RHRSW subsystem otherwise inoperable,

~dt/-'/e,fie>Y> ino erabl ubs ste t P RABLE stat us w1th resto re the at leas t one r:~i?"J~J OPER LE RHRSW pump within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> unless other in a) or b) below**, or be in at wi se specif1ect next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLO SHUTDOWNleas t HOT SHUTDOWN within the within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

a) When the 'A' RHRSW subsystem is inoperable to repa irs of the ' A' RHRSW subsystem piping, withallow for Generating Stat ion Unit 2 shutdown, reactor vess limeri ck removed and reac tor cavity flooded, the 72-hour el head Outage Time may be extended to 7 days once every Allowed calendar year with the followin com ensator ot er measures esta blish ed: ".- irJ ~rd'a.#ct:,. ~;.;-;

,~ ,Ci

.::z::d ~r,,,, ~ d G>t*,olm";,.n ?'ln<e. /?,-rt:' ,.."'

• • O nly one of thes e two Actions, eith er a.3 .a) or a.3. b) , may be entered on Unit 1 in a ca l enda r yea r . However, if ei ther Uni t 2 TS LCO 3.7. 1.l, Actio n a.3 . a) or a.3. b) has previously been entered in the cale ndar year , then Unit 1 Action a.3 .a) or a. 3. b) may not be entered during that same ca1endar year.

LIMERICK - UNIT l 3/4 7-1 Amendmen t No. W ,% ,-1-* , 203

3/4.7 PLANT SYSTEMS LIMITING CONDITION FOR OPERATION CCqptinuedl ACTION: (Continued)

1) The following systems and subsystems will be protected in accordance with applicab le station procedures:

• 'B' RHRSW subsystem

• ' B' ESW loop

• 'B ' and 'D' RHR subsystems

• 012, 014, 022, and 024 4kV buses and emergency diesel generators

• Division 2 and Division 4 Safeguard DC, and

2) The 'A' and 'B' loop of ESW return flow shall be aligned to the operable 'B' RHRSW return header only.

The ESW return valves to the 'B' RHRSW return header

{i.e., HV-11-0lSA and HV-11-0158) will be adminis tratively controlle d in the open position and de-energized prior to entering the extended AOT. The ESW return valves to the 'A' RHRSW return header (i.e., HV-11-0llA and HV 0llB) will be adminis tratively controlle d in the closed position and de-energized as part of the work boundary.

When the 'B' RHRSW subsystem is inoperable to allow for

) or- ,*n ~r o/tu1C.e- repairs of the ' B' RHRSW subsystem piping, with Limerick c-/ tf-h Y:-h.e.- 1"C:1~ k Generating Station Unit 2 shutdown, reactor vessel head removed and reactor cavity flooded, th 72-hour Allowed

_:r;:; ,C:,rrued Ci>pY/e--/-;~ Outa e Time may be tended to 7 da s once every other

-rl#Z<:- ff'!jrtllU #-.) ca en ar year w1 the o owing compensatory measures establis hed:

1) The following systems and subsystems will be protected i n accordance with applicab le station procedures:

• 'A' RHRSW subsystem

• 'A' ESW 1oop

• 'A' and 'C ' RHR subsystems

• Dll, Dl3, 021, and 023 4kV buses and emergency diesel generators

• Division 1 and Division 3 Safeguard DC, and

2) The 'A' and 'B' loop of ESW return flow shall be aligned to the operable ' A' RHRSW return header only.

The ESW return valves to the 'A' RHRSW return header (i.e., HV-11-0llA and HV-11-0118) will be adminis tratively controlle d in the open position and de-energized prior to entering the extended AOT. The ESW return valves to the 'B' RHRSW return header (i.e., HV-ll-015A and HV-11-0158) will be adminis tratively controlle d in the closed position and de-energized as part of the work boundary.

4. With both RHRSW subsystems otherwise inoperable, restore at least one subsystem to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLO SHUTDOWN* within the followi ng 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

• Whenever both RHRSW subsystems are inoperable, if unabl e to attain COLD SHUTDOWN as required by the ACTION, maintain reactor coolant temperature as (_ ..__,_)

low as pract i cal by use of alternat e heat removal methods. -___ /

LIME RICK - UNIT 1 3/4 7-l a Amendment Na . e&,se..~. 203 I

PLANT SYSTEMS EMERGENCY SERVICE WATER SYSTEM - COMMON SYSTEM

) LLMIIING CONDITION FOR OPERATION 3.7- 1.2 At leas t the following independent emergency with each loop comprised of: service water system loops,

a. Two OPERABLE emergency service water pumps, and

b. An OPERABLE flow path capable of taking suction from service water pumps wet pits which are supp the emergency the cooling tower basin and trans ferri ng thelied from the spray pond or Unit 1 and common safe ty-re lated equipment, water to the associated shal l be OPERABLE:

a. In OPERATIONAL CONDITIONS l, 2, and 3, two loops.

b. In OPERATIONAL CONDITIONS 4, 5, and* , one loop.

APPLICABILITY: OPERATIONAL CONDITIONS l, 2, 3, 4, 5, and*

• ACTIONi

a. In OPERATION CONDITION 1, 2, or 3:

..__, 1. With one emergency service water pump inoperable,

) inoperable pump to OPERABLE statu s within 45 days resto re the

• -"' leas t HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in or be in at within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. COLD SHUTDOWN

2. With one emergency service water pump in each loop restore at leas t one inoperable pump to OPERABLE inop erab le, 30 days or be in at leas t HOT SHUTDOWN within the statu s with in and in COLO SHUTDOWN within the following 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> s.

3. With one emergency service water system loop othe inoperable, declare all equipment aiigned to the rwise loop inoperable**, resto re the inoperable loop to inoperable statu s with at leas t one OPERABLE pump within 72 OPERABLE in at leas t HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> hoursn r be SHUTDOWN ithin the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. and in COLD t:!'J- /'fl 0.-CC,e>/"' tJ.H.(f ::. ePi=fJ.,

/

e.. j?;5y :;:

.:z:;, i<fr. .,,/ ~ 1-e./,",,n r;*..m.e 9rwt--.:> n-"

• When handling irrad iated fuel in the secon

• • The diese l generators may be aligned to thedary containment.

OPERA system 1oop provided confirmatory flow testi ng hasBLE emergency serv ice water dies el generators no aligned to the OPERABLE emerg been performed. Those loop shall be declar~perable and the actions ency service water system

1. During the extended~

of 3.8.1.1 taken.

Allowed Outage Time (AOT) spec 3.7. 1.l, Action a.3.a ) or a.3.b ) to allow for RHRSW ified by TS LCO the 72-hour AOT for one ino erable emer~ervi subsy stem piping repa irs, ce water system loop may also be extended to 7 days for the same~period.

• ' c1- in tt..C.-Ce> r dP-r t c e:. (,V; ./--),, ,.t-A.c F:s.k

.:Z-i'1-f;;.rn-i~ (,,t);kf>_/-c,f/'on /:m e 1'7-03,-a.--

UMERI CK - UNIT 1 3/4 7-3 Amendment No. ~.4@,%.,-1*, 203

PLANT SYSTEMS.

3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM J U MU.lliG.....Gl ND II ION FOR OP..E.MilD N 3.7.3 The reacto r core isolati on cooling CRCICl system shall be OPERABL an OPERABLE flow path capable of automa tically taking suction from the E with suppression pool and transfe rring the water to the reacto r pressure vessel APPLICABILITY: OPERATIONAL CONDITIONS l, 2, and 3 with reacto r steam dome pressu re greate r than 150 psi g.

I t:> ,... ; , , lfA ~c. .o,... clo.x c.e.. t.c.?;,4 ~ ;e/.s~

/

.:z:;t ~rMe cl ACTIOt;I: C-#1~/'k-h~ 7/J'h.c FJ-~~r~

a. With the RCIC system inoper able, operation may continue provided the HPCI sy tern is OPERABLE; restore the RCIC system to OPERABLE status within 14 dayc. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reacto r steam dome pressure to less than or equal to 150 psig within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. DELETED

c. Specif ication 3.0.4.b is not applica ble to RC(C.

)U RYE I,L~ANC E REO!JJ_RE!!.!M~J,..N66 I"6S==-====-===

4. 7. 3 fh e RC IC system sha11 be demons tra ted OPERABLE:

a. In acco rdance wit h t he Survei l l ance Frequency Cont rol Prog r am by:

l. Verifying loca t ions suscep tible to gas accumulation are suffic ientl y f i lled with water.

2. Ve r ifying t hat each va lve (manua l , power-operated , or automatic )

i n t he f low path that is not locked , seal ed, or otherw ise secured in posi tion, i s in its cor rect pos i t ion.**

3. Verifying that the pump flmv control l er is in the correct positio n.

b. In accordance wi t h t he Survei llance Frequency Contr ol Program ver ifyi ng that the RC lC pump develops a flew of greate r tha n orby eaual t o 600 gpm i n t he tes t fl ow path with a system head corresponding t o reacto r vesse l opera t ing pressure when steam is bei ng suppl ied to the t urbine at 1040 + 13 , - 120 psig.*

~ The provis ions of Specif ication 4.0.4 are not applic able, provided the survei llance is performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reacto r steam pressu re adequate to perform the test. If OPERABILITY is not succes sfully demons 1s within the 12-hour period , reduce reactor steam pressure to less than 150trated psig within the Following 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Not require d to be met for system vent flow paths opened under admin istrativ e

contro l.

)

UMEH l CV. unr

PLANT SYSTEMS 3/4.7.8 MAIN TURBINE BYPASS SYSTEM

) LIMITING CONDITION FOR OPERATION 3.7.8 The main turbine bypass system shall be OPERABLE as determined by the number of operable main turbine bypass valves being greater than or equal to that specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY: OPERATIONAL CONDITION l, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER.

ACTION: With the main turbine bypass system inoperable, restore the system to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or take the ACTION reguired by Specificatio n 3.2.3.c. or iYI tJ.~r-tl1N1t:..e wi-1-J, -l-1..c. ~,"'s ..

.:.rn ~ r114.ec./ u,,,,..,.,/enA,. r,'Pt.r:. ?r"69r~

4.7.8 The main turbine bypass system shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program:

a. By cycling each turbine bypass valve through at least one complete cycle of full travel,

b. By performing a system functiona l test which includes simulated automatic actuation, and by verifying that each automatic valve

) actuates to its correct position, and

c. By determining TURBINE BYPASS SYSTEM RESPONSE TIME to be l ess than or equal to the value specified in t he CORE OPERATING LIMITS REPORT.

)

LIMERICK - UNIT 1 3/4 7-33 Amendment No.** +.+/-,186

3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES A.C. SOURCES - OPERATING LIMITING CONDITION FOR OPERATION 3.8.1.1 As a minimum, the following A.C. electrical power sources shall be OPERABLE:

a. Two physically* independent circuits between the offsite transmission network and the onsite Class lE distribution system, and

b. Four separate and independent diesel generators, each with:

1. A separate day tank containing a minimum of 250 gallons of fuel,

2. A separate fuel storage system containing a minimum of 33,500 gallons of fuel, and

3. A separate fuel transfer pump.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION:

a. With one diesel generator of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C.

sources by performing Surveillance Requirement 4.8.1.1.1.a within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and at least once per 7 days thereafter. If the diesel generator became inoperable due to any cause other than an inoperable support system, an independently testable component, or preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining operable diesel generators by performing Surveillance Requirement 4.8.1 . 1.2.a.4 for one diesel generator at a time, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unless the absence of any potential common-mode failure for the remaining d~esel generators is determined. Restore the inoperable diesel generator to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See also ACTION e.

b. With two diesel generators of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C.

sources by performing Surveillance Requirement 4.8.1 . 1.1.a within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. If either of the diesel generators became inoperable due to any cause other than an inoperable support system, an independently testable component, or preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.4 for one diesel generator at a time, within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, unless the absence of any potential common-mode failure for the remaining diesel generators is determined. Restore at least one of the inoperable diesel generators to OPERABLE status within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s* or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See also ACTION e.

• During the extended~Allowed Outage Time (AOT) specified by TS LCD 3.7.1.1, Action a.3.a) or a.3.b) to allow for RHRSW subsystem piping repairs, the 72-hour AOT for two inoperable diesel generators may also be extended to 7 days 'for the same (8ii) peri ad 0 ,_ ;~~,..<:/a.,.,~ "';.'f'-4 ~e ,e;~

.:z;",~U-~e6~ 77.-r~ t9

3/4.8 ELECTRICAL POWER SYSTEMS LIMITING CQNQITJON FOB OPERATION (Cgnt1nuedl ACTION: {Continued) I/') *. '

c. With three diesel generators of the above required A.C. elect power sources 1noperable, demonstrate the OPERABILITY of the rical A.C. sources by performing Surveillance Requirement 4.8.1 .1.1.remaining 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> *ther eafte r; and perfor a within Surveillance Requirement 4.8.1 .1.2. a.4 for the remaining diesem within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Restore at least one of the inope l generator, rable diese to OPERABLE statu s within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in at least HOT SHUTD l gener ators within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the follow OWN 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See also ACTION e. ing

d. With one offsi te circu it and one diesel generator of the above A.C. elect rical power sources inoperable, demo required nstrate the OPERA of the remaining A.C. sources by performing Surveillance Requ BILITY 4.8.1 .1.1. a within, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> there irement If the diese l generator became inoperable due to any cause other after .

inoperable support system, an independently testa ble component than an

.preplanned preventive maintenance or testi ng, demonstrate the , or OPERABILITY of the remaining diesel generator by performing Surveillance Requirement 4.8.1 .1.2. a.4 for ones diese l generator at a time, within a hours, unless the absence of any poten tial common-mode failu re for the remaining diese l generators is determined.

least two offsi te circu its to OPERABLE statu s w1th1n 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />sRe tore at time of initi al loss or be 1n at least HOT SHUTDOWN within the from the hours and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See nex 2 ACTION e. also

)

~ 1:>- ;/11 11%-~rda-ne-e ~,~.fA -!he- ~s k

..:;;:#hl'-,,ne/ U,,.-,1' /e--~ ~n 77/µc.. 8-t!Jfr~,

LIMERICK - UNIT 1 Amendment No. ~. 4Q, 189

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION <Continued)

ACTION: (Continued)

e. In addition to the ACTIONS above:

1. For two train systems, with one or more diesel generators of the above required A.C. electrical power sources inoperable, verify within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter that at least one of the required two train system subsystem, train, components, and devices is OPERABLE and its associated diesel generator is OPERABLE. Otherwise, restore either the inoperable diesel generator or the inoperable system subsystem to an OPERABLE status within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s* or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. For the LPCI systems, with two or more diesel generators of the above required A.C. electrical power sources inoperable, verify within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter that at least two of the required LPCI system subsystems, trains, components, and devices are OPERABLE and its associated diesel generator is OPERABLE. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This ACTION does not apply for those systems covered in Specifications 3.7.1.1. and 3.7.1.2.

• During the extended~Allowed Outage Time (AOT) specified by TS LCO 3.7.1.1, Action a.3.a) or a.3.b) to allow for RHRSW subsystem the 72-hour AOT ma al so be extended to 7 da s for the samea=.;~

or ;A <k. cc.C' anc:..e. tAJ}-/-A -/-4e ~;$ .%"'"

C.o,,,. I e:/;p,,, / ,rr41 e... Pro~,-afl1, LIMERICK - UNIT 1 3/4 8-2 Amendment No. ~.~. 203

ELECTRICAL POWER SYSTEMS With one offsite c rcu1 o t e a ove require electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. Restore at least two offsite ci.rcuits to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> e.

in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and COLO S TDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

With .two of the above required offsite circuits inoperable, restore at least one of'the inoperable offsite circuits to OPERABLE status n our *or be in at least HOT SHUTDOWN withf n the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. With only one offsite circuit restored to OPERABLE status,

---..;~ore at least two off site ci rcu.i ts to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from time of initial loss or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

h. With one offsite circuit and two diesel generators of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirements 4.8.1.1.1.a within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. If either of the di*ese l generators became i noperab 1e due to any cause other than an inoperable support system, an independently testable component, or preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.4 for one diesel generator at a time, within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, unless the absence of any potential conunon-mode failure for the remaining diesel generators is determined. Restore at least one of the above required inoperable A.C. sources to OPERABLE status within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or be in a at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Restore at least two offsite circuits and at least three of the *above required diesel generators to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from time of initial loss or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLO SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See a1so ACTION e.

• i. Specification 3.0.4.b is not applicable to diesel generators.

LIMERICK - UNIT 1 314 8-2a Amendment No. 4G, ~.189

ELECTRICAL POWER SYSTEMS 3/4.8.2 O.C. SOURCES O.C. SOURCES - OPERATING LIMITING CONQIIION FOR OPEBAJION 3.8.2.l As a minimum, the following D.C. electrica l power sources shall be OPERABLE:

a. Division 1, Consisting of:

1. 125-Volt Battery lAl ClAlD101).

2. 125-Volt Battery 1A2 ClA2Dl01).

3. 125-Volt Battery Charger lBCAl C1AlD103).

4. 125-Volt Battery Charger 1BCA2 (1A20103).

b. Division 2. Consisting of:

1. 125-Volt Battery 181 (1810101).

2. 125-Volt Battery 182 (1820101).

3. 125-Volt Battery Charger lBCBl (1810103).

4. 125-Volt Battery Charger 1BCB2 ClB20103).

c. Division 3. Consisting of:

1. 125-Volt Battery lC ClCD101).

2. 125-Volt Battery Charger lBCC ClCD103).

d. Division 4, Consisting of:

1. 125-Volt Battery 10 (100101).

z. 125-Volt Battery Charger lBCD (100103).

APPLICABILITY: OPERATIONAL CONDITIONS l, 2, and 3.

ACTION: ti) ~,_  ;',, tfJLCce>~~&~ ~,:y.;, -rAe. ~sit J; ~rpe.e

n, /e-7",,"e>rl / ,,~#te- ?}-,p ,.-~

1. Restore battery terminal voltage to greater than or equal to the minimum establish ed float voltage within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />,

2. Verify associate d Division 1 or 2 float current !5 2 amps, or Division 3 or 4 float current .:S 1 amp within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafte r, and

3. Restore battery chargerCs) to OPERABLE status within

b. With one or more batteries inoperable due to:

1. One or two batteries on one division with one or more battery cells float voltage< 2.07 volts. perform 4.8.2.1.a .1 and 4.8.2.1.a .2 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for affected battery(s ) and restore affected cellCs) voltage

? Z.07 volts within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

z. Division 1 or 2 with float current> 2 amps, or with Division 3 or 4 with float current > 1 amp, perform 4.8.2.1.a .2 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for affected battery(s ) and restore battery float current to within limits within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.

LIMERICK - UNIT 1 3/4 8-10 Amendment No. 164

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION ACTION: (Continued)

3. One or two batteries on one division with one or more cells electrolyte level less than minimum established design limits, if electrolyte level was below the top of the pla.t es restore electrolyte level to above top of plates within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and verify no evidence of leakage(*) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In all cases, restore electrolyte level to greater than or equal to minimum established design limits within 31 days.

4. One or two batteries on one division with pilot cell electrolyte temperature less than minimum established design limits, restore battery pilot cell temperature to greater than or equal to minimum established design limits within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

5. Batter.ies in more than one division affected, restore battery parameters for all batteries in all but one division to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

6. (i} Any battery having both (Action b.1) one or more battery cells float voltage< 2.07 volts and (Action b.2) float current not within limits, and/or (ii) Any battery not meeting any Action b.l through b.5, Restore the battery parameters to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

With any battery(ies) on one div i sion of the above required D.C. electrical power sources inoperable for reasons other than Action b., restore the inoperable division battery to OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Otherwise, be in at least HOT SHUTDOWN within the COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

' cr  ; /1 A-CC. P r-c/a.-n c. e u,_, ; 4 rle. ~~ J:- ~ ,/;,,u."'C!j U~ /t:!--~*t'n /:'"'*-e ~"fT~

(*) Contrary to the prov1s1ons of Specificatio n 3.0.2, if electrolyte level was below the top of t he plates, the verification that there is no evi dence of leakage is required to be completed regardless of when electrolyte level is restored.

LIMERICK - UNIT 1 3/4 8-lOa Amendment No. 164 I

ELECTRICAL POWER SYSTEMS l IMITING CONDITION FOR OPERATION (Cont inued )

APPLICABILITY: OPERATIONAL CONDITIONS l, 2. and 3. t:JI"' iTt a.a:.ordlf.nc.e. <<;11-Ji

~e ;ie;sl:: ~hr""'e.d ACTION:

c,,,,,Y'/e-hPr? 7,'°',He ~!Y.r~~

a. With one of the above required Unit 1 A.C. distri butio n system divisi ons not energized, reene rgize the division within 24 be in at least HOT SHUTDOWN withi n the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in hours SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. COL

b. With one of the above required Unit 1 O.C. distri butio divisi ons not energized, reene rgize the divisi on withinn 8system be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and inhour SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. COL

c. With any of the above required Unit 2 and common distri butio n system divisi ons not energ ized, declaACre and/o the r DC assoc iated common equipment inoperable, and take the appropriate ACTION that system. for SURyE II LANCE BEOLJI REMENTS 4.8.3 .1 Each of the above required power distri butio n system be determined energized in accordance with the divis ions shall

') Program by verify ing corre ct breaker alignment Surve illance Frequency Control and voltage on the

./ busses/MCCs/pane 1s.

LIMERICK - UNIT 1 3/4 8-17 Amendment No. J.4, 186

ADM IN ISTRAIJ lLJ. CONIBQLS PROCEDURES AND PROGRAMS (Continued)

c. The program shal1, as al1owed by 10 CFR 50.SSa, meet Subsection "General Requirements," and Subsection !STD, "Preservice ISTA, Examination and Testing of Dynamic Restra ints (Snubbers> and lnservice Water Reactor Nuclear Power Plants ," in lieu of Section XIin ofLight-B&PV Code IS! requirements for snubbers, or meet authorized the ASME altern atives pursuant to 10 CFR 50.SSa.

d. The 120-month program updates shall be made in accordance with 10 S0.5Sa subjec t to the limita tions and condit ions listed CFR therein .

1. Exolosive Gas Monitoring Program This program provides contro ls for potent ially explosive gas mixtur contained downstream of the off-gas recombiners. es The program shall include:

a. The limit for the concentrat1on of hydrogen downstream of the offgas recombiners and a survei llance program to ensure the limit maintained. This limit shall be approp riate to the system'sis design criter ia Ci .e., whether or not the system is designed to withstand hydrogen explos ion); a The provis ions of SR 4.0.2 and SR 4.0.3 are applic able to the Explos Monitoring Program survei llance frequencies. ive Gas LIMERICK - UNIT 1 6-14e Amendment No. m, 228

REACT!VlTY CONTROL SYSTEMS 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM I IMIT!NG CONDITION FOR OPERATION 3.1.5 The standby liquid control system shall be OPERABLE and consist of the following:

a. In OPERATIONAL CONDITIONS 1 and 2, two pumps and corresponding flow paths,

b. In OPERATIONAL CONDITION 3, a minimum of one pum and corresponding flow path. -

t:>;- /;J ~rda_ / nce-

-:_i)

UJ,r;,

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3 rl.e- )?;"'.s/c- ~.,4r4u:u:f ACTION: c,~ /e:fith? /,i-K~ /?tr/.tr4.H--..,

a. With only one pump and corresponding explosive valve OPERABLE, OPERATIONAL CONDITION 1 or 2, restore one inoperable pump and corresponding explosive valve to OPERABLE status within 7 days in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

b. With standby liquid control system otherwise inoperable, in OPERATIONAL CONDITION l, 2, or 3, restore the system to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

' ")

SURVEILLANCE REQUIREMENTS 4.1.5 The standby liquid control system shall be demonstrated OPERABLE:

a. In accordance with the Surveillance Frequency Control Program by verifyin g that:

1. The temperature of the sodium pentaborate solution is within the limits of Figure 3.1.5-1 .

2. The available volume of sodium pentaborate solution is at least 3160 gallons .

3. The temperature of the pump suction piping is within the limits of Figure 3.1.5-1 for the most recent concentration analysi s.

LlMERICK - UNIT 2 3/4 1-19 Amendment No. 64,~.49.~,-14+. 163

3/4.3 INSTRUMENTATION.

3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OpERATION 3.3.1 As a minimum, the reactor protection system instrumentation channels shown in Table 3.3.1-1 shall be OPERABLE with the REAC PROTECTION TEM RESPONS TIME as shown in Table 3.3.1-2. l or >'n ae-CCJ,-Ja.J?u f.AJ,--fh -t/.c..

APPLICABILITY: As shown in Table 3.3.1-1. /e'.Jk .::z:;,/()n?tec/ C~,Ple-hM ACTION: '?idle, rr-~..f~j -*"~

Note: Separate condition entry is all owed for each channel .

Note: When Functional Unit 2.b and 2.c channels are inoperable due the calculated power exceeding the APRM output by more than 2% of RATED THERMAL POWER while operating at ~ 25% of RATED THERMAL POWER, entry into the associated Actions may be delayed up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

a. With the number of OPERABLE channels in either trip system for one or more Functional Units. less than the Minimum OPERABLE Channels per Trip System required by Table 3.3.1-1, within one hour eac a ec e u unit either verify that at least one* channel in each trip system is OPERABLE or tripped or that the trip system is tripped, or place either the affected trip* system or at least one inoperable channel in the affected trip system in the tripped condition.

b. With the number of OPERABLE channels in either trip system less than Minimum OPERABLE Channels per Trip System required by Table 3.3.1-1, plac either the inoperable channel(s) or the affected trip system** in the tripped condition within 12 h o u r s r - - - - - - - - - - - - - - -

c. With the number of OPERABLE channels in both trip systems for one or more Functional Units less than the Minimum OPERABLE Channels per Trip System required by Table 3.3.1-1, place either the inoperable channel(s) in one trip system or one trip system in the tripped condition within 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s* .

d. li within the allowable time allocated by Actions a, b or c, it is not desired to place the inoperable channel or trip system in trip (e.g., full scram would occur), lb.en no later than expiration of that allowable time initiate the action identified in Table 3.3.1-1 *for the applicable Functional Unit.

• For Functional Units 2.a, 2.b, 2.c, 2.d, and 2.f, at least two channels shall be OPERABLE or tripped. For Functional Unit 5, both trip systems shall have each channel associated with the MSIVs in three main steam lines (not necessarily the same main steam lines for both trip systems) OPERABLE or tripped. For Function 9, at least three channels per trip system shall be OPERABLE or tripped.

• • For Functional Units 2.a, 2.b, 2.c, 2.d, and 2.f, inoperable channels shall be placed in the tripped condition to comply with Action b. Action c does a r the F ional Un' J,*' J _ /- 1

~ A/of 'f'/;cttl,le ~ n -fr; C¥<< ,*,=ry ,-.s ~T ,.,ieutrf~

'r C... O,..- "'71J'"C.. -F'Krl 4P fft:I- ?/HI~.!>

• INSTRUMENTATION 3/4.3.2 . ISOLATION ACTUATION INSTRUMENTATION

!MITING CONDITION FOR OPERATION 3.3.2 The isolatio n actuatio n instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoint s set consiste nt with the values shown in the Trip Setpoin t column of Table 3.3.2.-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3 .

APPLICABILITY: As shown in Table 3.3.2-1.

ACTION:

a) With an

• isolatio n actuatio n instrume ntation channel trip setpoint less conserv ative than the value shown in the Allowable Values column of Table 3.3.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consiste nt with the Trip Setpoin t value.

b) With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirements for one trip system:

1. If placing the inoperable channel Cs) in the tripped* condition would cause an isolatio n, t e inoperable channel(s) shall be restored to OPERABLE status within 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> If this cannot be accomplished, the ACTION required by .Table

.3.2-1 for the affected trip function shall be taken*, or the .channel shall be ~laced in the tripped condition.

or

2. If placing the inoperable channel(s) in the tripped condition would not cause an isolatio n, the inoperable channel(s) and/or that trip system shall be placed in the tripped condition within:

b) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for trip function s not common* to RPS Instrum entation .

c:>r- ; n ~rzlt:U'tCC!. c,,o;-f-}. -r/i e- R:'.S k ~/;;;-;~CJ eoi~ 1en~~ 7,~~ /?-c:Jr-A>>-t ** *

• Trip function s common to RPS Actuation Instrume ntation are shown in Table 4.3.2.1- 1.

~"'"" Nd ~l'l'/;cei.l.k ~en -fry.. <:or,d;i,./y ,:.r ,,~/,,_,,,._;~,.;nd_

71" /Yt?f °#;,*caJk /;,,.. Pe<.Ae-..f;JJn lj' .k-u:>~ CDef..-.;,..,Ate;i.-/

z::s "It::'-,L;e1// .

LIMERICK - UNIT 2 3/4 3-9 Amendment No. -l-7, ~. 132

I NSTRUMENTATIO~

3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3 The emergency core cooling system (ECCS) actuation instrumentation channels shown in Table 3.3.3-1 shall be OPERABLE with their trip setpoints set consiste nt with the values shown in the Trip Setpoint column of Table 3.3.3-2 and with EMERGENCY CORE COOLING SYSTEM RESPONSE TIME as shown in Table 3.3.3-3.

APPLICABILITY; As shown in Table 3.3.3-1 ACTION:

a. With an ECCS actuatio n instrumentation channel trip setpoint less conserva tive than the value shown in the Allowable Values column of Table 3.3.3-2. declare the channel inoperable until the channel is restored to Operable status with its trip setpoint adjusted consiste nt with the Trip Setpoint value.

b. With one or more ECCS actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.3-1.

c. With either ADS trip system subsystem i noperable, restore the inoperable trip system to OPERABLE status within:

1. 7 day , provided that the HPCI and RCIC systems are OPERABLE.

2.

Cir /',, ~rd'i::t.Hc.e. "'; rh 1"-Ae .,e,.::s k

-:z::-n,t:.;r#ted ~ /e.r,(>11 77me- n--~~rp..;;...._ ,...........

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> )

and reduce reactor steam dome pressure to less than or equal to ',_.~*

100 psig within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

S.URV EJilMC E..B,~OU I REMENTS 4.3.3.1 Each ECCS actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS shown in Table 4.3.3.1- 1 and at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3.3.1- 1.

4.3.3.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed in accordance with the Surveillance Frequency Control Program.

4.3.3.3 The ECCS RESPONSE TIME of each ECCS trip function shown in Table 3.3.3-3 shall be demonstrated to be within the limit in accordance with the Surveilla nce Frequency Control Program. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times the frequency specifie d in the Surveillance Frequency Control Program where N is the total number of redundant channels in a specific ECCS trip system.

LIMERICK - UNIT 2 3/4 3-32 Amendment No. J-4,147

TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION STATEMENTS ACTION 30 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. With one channel inoperable, place th inoperable channel in the tripped condition within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the associated system inoperable.

b. With more than one channel inoperable, declare the associated system inoperable.

ACTION 31 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, declare the associated ECCS inoperable within .24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 32 - DELETED ACTION 33 - With the numbe~ of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> r declare the associated ECCS i.noperable.

ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. For one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the HPCI system inoperable.

b. With more than one channel inoperable, declare the HPCI system inoperable.

ACTION 35 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the HPCI system inoperable.

With the number of OPERABLE channels less than the Total Number of Channels, declare the associated emergency diesel generator and the associated offsite source breaker that is not supplying the bus inoperable and take the ACTION required by Specification 3.8.1.1 3.8.1.2, as appropriate.

or /n ~rz1~ ~;f), ~ Z:sk

~,t;,..,,,,eef Ce>,.,,,/e,,f;~,, ~e ffz,r;,p-1AAt;J..

t:'r iA P-CCPrdA.hce. t.c-1'~r M r;(e,. Z-s I::

...:;::;, ,t;rmecf uPm)>/ef,"~ /,',,ce_ ffz::Jr4ffl.::, ~

MERICK - UNIT 2

• ;../of ~I' ~~~ euhen

INSTRUMENTATION

• 3/4.3.4' RtCIRCULATION. PUMP. TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION

• LIMITING CONDITIO~ FOR O~ERATION 3.3.4.l The! ~ritic~~a~ed . transient with~ut . ~cr~m recircu~~tion pump trip .

• CATWS-RPT> system instrumentation channels shown in .Table 3~3.4.1- .1 shall be

• OPERABLE with their trip setpoi11ts set consistent . valu int

. ..*Setpoitit column _of

• Table: 3.3 .~ 4.} ~ 2.  :>or* ";n ~Yc/iU4c:.e. "';~ ~t!!

APPLICABlLITY: .

• OPERATIONAL CONDITION L #,:SJ. Pr ~r~e-~ c;.,,,_f'/e-1-,";t

• ACTI~N: *. 7'},;ee ~ rrA-~~ * .. ** .. * . .

.* a. * .With a~ ATWS r~:circulation pu~p trip system -instrumentation channei trip setpoint less conservative than the value shown in the Allowable

• Values column

• of Table 3.3.4.1-2, declare the channel inoperabl~ until the ~han~el is restored to OPERABLE status .with the channel trip setpoint adjusted .consistent with the TripSetpoint value.

• b.

• With the, number o.f OPE.RAB LE channels one less: thari* required by the **

• Minimum OPERABLE Channels per Trip System requirement for one or both trip systems1 place the inoperable channel(s) in the .tripped condition

. within 24..

hciurs r*.*- - - - -. - - -*- - - - - - - - - - - - - -

. c.

• With the number of PPERABLE. channels two or more less than required .

• by the-Mini mum OPERABLE Channels per Trip System requirement for one .

• trip system and~ * * . . .* .

• 0-..

1. If the inoperable' charinelS con~.i st of one reactor. vessei. ~at~'r - * . \J .

level channel and ..orie reactor vessel pr:essure . channel, pl ac *. both inoperable thannels in .the tripped condition within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ~ or, if this action will initiate a pump trip, .detlare the trip sy e inoperable. ** * * * *

2.

• if th~ in~perabl~ channel~ include two .reactor ves~el . ~ater level

• channels or two reactor vessel pressure channels, declare the .

trip system inope~able. *

• d.

e.

SURVEILLANCE REQUIREMENTS

• 4.3~4.l.l Each of the required ATWS recirculation pump trip system instrumentation channels shall be demonst~ated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies I specified in the S~rveillance Frequency Control Program.

4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed in accordance with the Surveillance Frequency J.--

Co ol Pro ram .

~*N'tr1-A;t>l't'~l/t!. wk,,~~ ~/j'l i.s Ael-~n./Linecl LIMERICK - UNIT 2 3/4 3-42 Amendment No. JJ, J.4, 1.47

INSTRUMENTATION ENO-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR QPERATION 3.3.4.2 The end-of-cycle recirculation pump trip CEOC-RPT) system instrumentation channels shown in Table 3.3.4.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.4.2-2 and with the ENO-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME as shown in Table 3.3.4.2-3.

APPLICABILITY: OPERATIONAL CONDITION l, when THERMAL POWER is greater than or equal to 29.5% of RATED THERMAL POWER.~ O'r- /n a.c<4r-dAnC.e ~,':.fh -/A_e_

~;.sf: ~/,r~ee/ C°4'>,,.nl°/e-~o,,

ACTION:

a.

, ~e.-- 71? ,,_t:..,,n

• With an end-of-cycle recircu a on pump rip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4 : 2-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel(s) in the tripped condition within 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />

c. With the number of OPERABLE channels two or more less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system and:

1. If the inoperable channels consist of one turbine control valve channel and one turbine stop valve channel, place both inoperable channels in the tripped condition within 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> .

2. If the inoperable channels include two turbine control valve channels or two turbine stop valve channels, declare the trip system inoperable.

d. With one trip system inoperable, restore the inoperable trip system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or take the ACTION required by Specification 3.2.3.

e. With both trip systems inoperable, restore at least one trip system to OPERABLE status within one hour or take the ACTION required by Specification 3.2.3. * / 'LJ ....J/

, or 1n e;....c.C..t:'rcf/l.YtC.C. ,,,p,-,, 7"'-e..

?~' .:z:;, ~rmc/ c;,~/e://'~n 77°Au!- Pr~,-~~

LIMERICK - UNIT 2 3/4 3-46 Amendment No. JJ, 163

TABLE 3.3.5-1 (Continued)

REACTOR CORE ISOLATION COOLING SYSTEM ACTION STATEMENTS

. . . . (

.. ACTION 50 -

• With the

• number of OPERABLE* channels less than required by the

• - .c_/

Minimum OPERABLE Channels per . Trip Functidn requirement: *. *. *

.._ .

• With one channel inoperable; place, the . inoperable channel in .

the; tripped condition within

• 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the

• RCIC *** 1*

system: inoperable~ * * ..* *..* . * * *. . * .. .* * . *.. * .

b. With. more than one channel inopera~le* declare the : RCIC system

• inoperable * .

ACTION:. 51-

• With .the number of OPERABLE channels* less . than required by the

• minimum OPERABLE channels per Trip System requirement, declare the .. '.

• i.-

RCIC system -inoperab.le within

24. hours. * *

• ACTION 52 - Wi.th the ntimber of OP~RABLE channels less than required by the .

MinimunrOPERABLE Channels per. Trip System .requirement, .. place *at . .

least* one:dnopera ble channel in -. the -. tripped condition* within 24 * *

• • I.

hours o~: declare the RCIC'*system

• inoperable *.- .

---

~ . .

• - . With the number of OPERABLE channels one less than required by the MinimumOPERABLE Channels per Trip Systemrequ1rement 9 restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or declare the *

• I

. . RCIC system inoperable. *

• )or ;h- ~ ~ce * ,p/" - kPs/.

. :;G~r~ U,~ k1'J1'7 /;'Ate .~e:frhh_,

~ Cr- ,;,, ()t. cce;re/an ce_ c,v#:/-J f-A_e- ?:s ./:

~Ar~~,P/J,;,~ /;""'~ 8';/r~J ~

~~~k ~~ .,t:r~ e-r~£,/,1' /s ~/Ha,;~~J. (

LIMERICK - UNIT 2 3/4 3-54 Amendment No. 17 nrr 1 '7 tQDt I

INSTRUMENTATION 3/4.3.9 FEEDWATER/MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTAT ION LIMITING CONDITION FOR OPERATION ()

3.3.9 The feedwater/main turbine trip system actuation instrumentation channels shown in the Table 3.3.9-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.9-2.

APPLICABILITY: As shown in Table 3.3.9-1 ~ If';- /n ~rc/~>t..C-e... ~:+Ji -f-Ji.e ACTION:

?,j. k cZ/J ~d ~.f>/d:i,n

/,~ J?--&>.:f;-- a.,;n:>

a. With a feedwater/main turbine trip system actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.9-2, declare the channel inoper -

able and either place the inoperable channel in the tripped condition unti l the channel is restored to OPERABLE status with its tri p set-point adjusted consistent with the Trip Setpoint value, or declare the associated system inoperable.

b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels requirement, restore the inoperable channel to OPERABLE status within 7 days or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

c. With the number of OPERABLE channels two less than required by the Minimum OPERABLE Channels requirement, restore at least one of the inoperable channels to OPERABLE status wi thin 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

, 17,_ ; n ~t::1U'tc.e u...>;-1-A -rli e. ,e,* s./: .lf- Nr ~ ~r"'7ed" Ul'kJ"/d,"e >n ~e- ~ ra.~ 1 4.3.9.1 Each of the required feedwater/main turbi ne trip system actuation instrumenta tion channels shall be demonstrated OPERABLE* by the performance of the CHANNEL CHECK , CHANNEL FUNCTIONAL TEST, and CHANN EL CALIBRATION operations at the frequenci es speci fied in the Surveillance Frequency Control Program.

4 .3.9.2 LOG IC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shal l be performed i n accordance wi th the Survei l lance Frequency Control Program.

• A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveil l ance without pl aci ng t he tri s stem in the tripped condi t ion.

LIMERICK - UNIT 2 3/4 3-112 Amendment No. JJ, J4, 147

REACTOR COOLANT SYSTEM

~ 3/4.4 .7 MAlN STEAM LtNE ISOLATION VALVES lIMITING CONQITION FOR OPERATION 3.4.7 Two main steam line isolat ion valve s CMSIVs) per main steam be OPERABLE with closing times great er than or equal to 3 and less line shall equal to 5 seconds. than or ACTION:

a. Maintain at least one MSIV OPERABLE in each affect ed main steam line that is open and withi n 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> , either :

1. Restore the inope rable valve (s) to OPERABLE status , or

2. Isolat e the affect ed main steam line by use of a deact ivated MSIV in the closed positi on.

b. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. and in 4.4.7 Each of the above required MSIVs shall be demonstrated OPERAB verify ing full closur e between 3 and 5 seconds when tested pursua LE by Speci ficati on 4.0.5. nt to LIMERI CK - UNIT 2 3/4 4-23 Amendment No. 132

EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERATION fContjn uedl ACTION; er ;n P-C-C--(!)r-dt:U-f-C.C.. ""'"r.h ~e-

' ,/:? k :z:-,,,Lbr.1nee/ c,~/'/e---Ti

a. For the core spray system: -r;',1/_s t1e-e ~<?/Jl""a.H1..3 c/J

1. .

With one CSS subsystem inopera e, provid subsystems are OPERABLE, restore the ino e tha t at lea st two LPCI OPERABLE sta tus within 7 day rable CSS subs stem to the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COL s SHUT or be in at east HOJ SHUTDO DOWN within the following 24w1t WN hin

2. With both CSS subsystems inoperable, be hou rs.,

in within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN wit at lea st HOT SHUTDOWN hin the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. For the LPCI system:

l. With one LPCI subsystem inoperable, pro subsystem is OPERABLE, restore the inoper vided tha t at lea st one CSS sta tus within 30 days or be in at lea st able LPCI pump to OPERABLE next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN withinHOT SHUTDOWN within the the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. With one RHR cro ss- tie valve (HV-51-282 removed from one closed RHR cro ss- tie valA or 8) open, or power not open valve and/or remove power from the ve operator, close the within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or be in at lea st HOT closed valves operator and in COLD SHUTDOWN within the next 24SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> hours.

3. With no RHR cro ss- tie valves (HV-51-282 not removed from both closed RHR cro ss- A, B) closed, or power with one RHR cro ss- tie valve open and pow tie valve operators, or the other RHR cro ss- tie valve operator, er not removed from SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHU be in at lea st HOT 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. TDOWN within the next

4. With two LPCI subsystems inoperable, pro subsystem is OPERABLE, res tor e at lea st vided tha t at lea st one CSS OPE LE tatu s wi hin da or be in three LPCI subsystems to the ~ext 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN at lea st HOT SHUTDOWN w;thin With three LPCI subsystems inoperable, within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. l subsystems are OPERABLE, restore at leaprovided tha t both CSS atus wit in 72 ho s or be instattwoleaLPC st I subsystems to the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN HOT SHUTDOWN wit within the following 24 houhin rs.

With all four LPCI subsystems inoperabl SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHU e, be in at lea st HOT 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.* TDOWN within the next

" ,.. ,n Ol-C-CCtr- c/t>-.l"lt:.e &C-?/-7'-,;, -rA. f!- ? ~ k .z::;, 4rM-ecl C6J...nf'Ie.-YI.*",, 77nt.W!! ?~r~,

• Whenever both shutdown cooling subsystem COLD SHUTDOWN as required by thi s ACTIONs are inoperable, if unable to att ain as low as practical by use of alte rna te , maintain rea cto r coolant temperature heat removal methods.

.HOV 1 6 1998 LIMERICK - UNIT 2 3/4 5-2 Amendment No. 56, Te, 92

EMERGENCY CORE CQQLING SYSTEMS Lili.IT I NG CONDIIliW EO.B=QEERAT::IO::Ll~C::!o~n:::;tUl::;.~Y,esi~~:::::::=::::::::::::::====:::===

) ~~=~~~.......

ACTION: (Continued) o,- /J? ~d~ce tG:l;-f); -r--k ;?/~ k ~

C,,"'71"/e--Ae>n /l,,n e ?ro,fr~~

c. Far the HPCI system:

1. With the HPCI syste~ inoperab le, provided the CSS, the LPCI system, the ADS and the RCIC system are OPERABLE, restore the HPCI system to OPERABLE status within 14 days or be in at east HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to.,; 200 psig within the following 24 tlours.

2. With the HPCI system inoperab le, dnd one CSS subsystem, and/or LPCI subsystem inoperab le, and provided at least one CSS subsystem, three LPCI subsystems, and ADS are o erable, restore the HPCI to OPERABLE within 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> , or be in HOT SHUTDOWN in the next 2 ours, dnd in COLD SHUfDOWN in the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3. Specific ation 3.0.4.b is not applicab le to HPCI.

d. For the ADS:

1. With one of the above required ADS valves inoperab le, provided the HPCr system, the CSS and the LPCI system are OPERABLE,

'------~e~s~t~o!..r:,.e the inoperab le ADS valve to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and re uce reactor steam dome pressure to ~ 100 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. With two or more of the above required ADS valves i noperabl e, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to ~ 100 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

e. With a CSS and/or LPCI header ~P instrume ntation channel inoperab le, restore the inoperab le channel to OPERABLE status withi n 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or determ i ne the ECCS header ~P locally at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />; otherwi se, declare the assoc i at ed CSS and/or LPCI, as applicab le, inoperab le.

f. DELETED

)

......-'~

LIMERICK - UNIT 2 3/4 5-3 Amendment No. ~. ~. 172

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK LIMITING CONQITION FOR OPERATION 3.6.1.3 The primary containment air lock shall be OPERABLE with:

a. Both doors closed except when the air lock is being used for normal transit entry and exit through* the containment, then at least one air lock door shall be closed, and

b. An overall air lock leakage rate in accordance with the Primary Containment Leakage Rate Testing Program.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2*, and 3.

ACTION:

a. With one primary containment air lock door inoperable:

1. Maintain at least the OPERABLE air lock door closed and either restore the inoperable air lock door to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or lock the OPERABLE air lock door closed.

Operation may then continue until performance of the next required overall air lock leakage test provided that the OPERABLE air lock door is verified to be locked closed at least once per 31 days.

3. Otherwise, be in at 1east HOT SHUT.DOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With the primary containment air lock inoperable, except as a result of an inoperable air lock door, maintain at least one air lock door closed; restore the inoperable air lock to . OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

~,.- ;,, ~da.xce. ~~7i f-k  ?;.$) .;:z:;hr~:c/

C4P',/e.ft;,n ;;-~ ?r~r-lt>>1~

• See Special Test Exception 3.10.1.

LIMERICK - UNIT 2 3/4 6-5 Amendment No. i*, 132

CONTAINMENT SYSTEMS SUPPRESSION POOL SPRAY

(____,

) LIMITING CONDITION FOR OPEBAI _

3.6.2 .2 The suppression pool spray mode of the residu al heat system shall be OPERABLE with two independent loops, each loop removal CRHR) consi sting of:

a. One OPERABLE RHR pump, and

b. An OPERABLE flow path capable of recirc ulatin g water from the suppression chamber through an RHR heat exchanger and the suppression pool spray sparg er(s).

APPLICABILITY:

ACTION:

a. With one suppression pool spray oop inope rable, restor e the inope loop to OPERABLE status within 7 days or e in at least HOT S rable within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD HUTDOWN within the follow 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ing

b. With both suppression pool spray loops inoperable, restor e at least one loop to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN* within following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. the

- ...\

,SUR.Y._~JJ,.JANC E REOU I REMENTS

~ 4.6.2 .2 The suppression pool spray mode of the RHR system shall OPERABLE: be demonstrated

a. In accordance with the Surve illanc e Frequency Control Program by verify ing that each valve (manual, power-operated, or autom atic) in the flow path that is not locked, sealed , or otherwise secured in positi on, is in its correc t positi on.

b. By verify ing that each of the required RHR pumps develops a flow at least 500 gpm on recirc ulatio n flow through the RHR heat exchanof and the suppression pool spray sparger when tested pursuant to ger ficati on 4.0.5. Speci-

c. By verify ing RHR suppression pool spray subsystem locati ons susce ptible to gas accumulation are suffici~ntly filled with water in accordance with the Surve illanc e Frequency Control Program.

• Whenever both RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as requir ed by this ACTION, maintain reacto r coolan as low as pract ical by use of altern ate heat removal methods t. temperature

.J LIMERICK - UNIT 2 3/4 6-15 Amendment No. J-O,+G,-9-2-,-W, 178

CONTAINMENT SYSTEMS SUPPRESSION POOL COOLING

!,JMIIING CONDITION FOR OPER..AI~IO~N=====

===========

3.6.2 .3 The suppression pool cooling mode of the residu al heat system shall be OPERABLE with two independent loops , each loop removal CRHR) consi sting of:

a. *One OPERABLE RHR pump, and

b. An OPERABLE flow path capable of recirc ulatin g water from the chamber through an RHR heat exchanger. suppression APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3. f'. j ACTION:

p , - / /? ~cord't::c-J;tce,. ""-' ;._/-h -r:-Ae. ;?;.s .J:. :z:n~ l?'k..e

~/'/e1'1C.n /7N1 e- ~..Y~

a. With one suppression pool cooling loop inope rable, restor e the loop to OPERABLE status within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s** or be in at least H inoperabl within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHU DOWN within the follow WN hours. ing 24

b. With both suppression pool cooling loops inoperable, be in at SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN* within the next least HOT 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

5URVE I LLMKE Rf_QUJ_REMENTS 4.6.2 .3 The suppression pool cooling mode of the RHR system shall OPERABLE: be demonstrated

(')*-*"-

a. In accordance with the Surve illanc e Frequency Contro Program by \

verify ing that each valve (manual, power-operated, orl autom atic) in the flow path that is not locked, sealed , or otherwise secured in is in its corre ct positi on. positi on,

b. By verify ing that each of the required RHR pumps develops a flow least 10,000 gprn on recirc ulatio n flow through the flow path includ of at the RHR heat exchanger and its assoc iated closed bypass valve , ing suppression pool and the full flow test line when tested pursua the Specificati-0n 4.0.5 . nt to

c. By verify ing RHR suppression pool cooling subsystem locati ons susce to gas accumulation are suffic iently filled with water in accord ptible the Surve illanc e Frequency Control Program. ance with

• Whenever both RHR subsystems are inope rable, if unable to attain as requir ed by this ACTION, maintain reacto r coolant temperature COLD SHUTDOWN pract ical by use of altern ate heat removal methods. as low as

• '*puring the extended~Allowed Outage Time (AOT) specif ied by TS LCO 3.7.1 .1, Action a.3.a) or a.3.b) to allow for RHRSW subsystem piping repair s, the 72-hour AOT for o~e (i;=~ble.suppression pool cooling loop. may also be extend ed to 7 days for the scrne day period .  ;:_:::>,,*,, ~(:)rdt::U?~ w;..r;, -hC:..c- l!?/:.sk- ,_)

....i. n.,...,,,_rl't.ed Ce>.ay/-e-lfPn 7T~e ;?-e;,,Jr<<..n-...

LIMERICK - UNIT 2 3/4 6- 16 Amendment No . .;m,+Q,.Q.J.,l-4+, 16~. 178

CONTAINMENT SYSTEMS

, 3/4.6 .3 PRIMARY CONTAINMENT ISOLATION VALVES

\:---~~) LIMITING CONDITION FOR OPERATION*

3.6.3 Each primary containment isolat ion valve and each instrumentation line flow check valve shall be OPERABLE. excess APPLICABILITY: OPERATIONAL CONDITIONS l, 2, and 3~ _ }::-

-. t:7,.. ,in a.,cc .o,--e/~c e. """ , i -f-Ae j?, ..S -

ACTION: xri~r~e./ &. /e:l-,,~H / ,~t:- ~!}ret*'!J

a. With one or more of the primary containment isolat ion maintain at least one isolat ion valve OPERABLE in each valves inoperable,**

affected penetration that is open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> e~i'...!:t:!.:h::er~=---

1. Restore the inoperable valve(s) to OPERABLE status , or

2. Isolat e each affected penetration by use of at least one de-activated automatic valve secured in the isolated positi on,* or

3. Isolat e each affected penetration by use of at least one closed manual valve or blind flange.*

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLO SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

~ -......,_\

b. With one or more of the instrumentation line excess flow check valves inoperable, operation may continue and the provisions

--~-~~) Specification 3.0.3 are not applicable provided that within of hours either : 4

1. The inoperable valve is returned to OPERABLE status , or

2. The instrument line is isolat ed and the associated instrument is declared inoperable.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c. With one or more scram discharge volume vent or drain valves inope perform the applicable actions specified in Specification 3.1.3 .1. rable,

• Isolation valves closed to satisf y these requirements may be reopen interm ittent basis under administrative control. ed on an

• fr* Except for the scram discharge volume vent and drain valves.

_)

LIMERICK - UNIT 2 3/4 6-17 Amendment No. +/-Q-7., 1-J..l., ~. 153

CONTAINMENT SYSTEMS

"') 3/4.&.* VACUUM RELIEF SUPPRESSION ClfN:SER

• DRVWELL VACUUM BREAKERS LIMITING COHDITlON FOR OPERATION 3.6. 4.l Three pai,-s of suppression chlliber

• dr,well vac:u1 OPERABLE and all suppression chllllber

• d~'l vac:wa braa11 b'i"Q k rs Ghlll be urs s~n be closed.

APPLICABILm: OPERATIONAL CDNDmOHS 1, z. and 3. - /'

ACTION* o-r //I ~,.-c/a.nc.e fP;f l, "1'"lie. z.s k .:i:N'f?l17t1ec/-

I

......,.oiiioiiiiioio. Qp,, , lc:..'4#nr ;?7;?U!. ~t?!frlfV'>, :>

Witfi ona ar vacu

• rea rs n ane 5upp ressi on c:b Ir'

• dryt'1911 YICIAO brut ar pairs,.. roquired pa;n of but known to be closed, rt!Sto l'I It la.st. OM i ir=pa rlbl* fol' Ol)tning break eH to OPEMILE stat.us withi n 72 hDUl"I r nbl* patr of YOCUD s~ t:rlthtn the naxt l2 hoU1'1 and . in IJ> SWT'OO'lil wttlltn tm following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. Witb one suppression chlllbel" "' dr)M lll vacuum breat the other vaCUU11 bl"'O ur tn th2 pair to car Ol'Qft, val"ify closst d rest.ore the open vocuam bT"Oakar to tl't2 clasQd position n Z houn ;

withi or b1 in at 1 nst. KOT SKUTDO\flt wfth1n the ooxt. U hoUf'Iwftl\t n 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ud in COLD SHUTDOWN with in thl following 24 houn .

c. With one position indicator of any suppression c:hmibor

• vacum bnakel" inoperable: d~ll

1. Verify the other vacum breaker in the p ir ta be closed with 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and t 1east ance per lS days there after in 1 ol'"

%. Verif y the v cum brea ker(s ) with the inap anbl e posit indic ator* to be closed by conducting tast ion that the AP is aaintained at graater than orwhich ra.qual dai:lanstratts 0.7 psi for one ho&n- witho ut ukeup mth1 n 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mt at. to l nut cncG per lS days there after .

Othe Nhe , be in It lens t HOT SmtrDCW wtthtn the nm in COLO SHUTDOWN t:rf th1n the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> nd LU1ERICK

• UNIT 2 3/4 G*44 A!aondloot !lo. 9 OCTO2 llll I

3/4.7 PLANT SYSTEM.5, 3/4.7 .1 SERVICE WAIER SYSTEMS RESIDUAL HEAT REMOVAL SERVICE WATER SYSTEM - COMM ON SYSTEM

'""~,) I IMIT!NG CONDITION FOR OPERAIJON 3.7.1 .1 At leas t the following independent residual heat

<RHRSW) system subsystems, with each subsy removal serv ice water stem comprised of:

a. Two OPERABLE RHRSi~ pumps, and

b. An OPERABLE flow path capable of taking suction from water pumps wet pits which are supplied the RHR serv ice from cooling tower basin and tran sferr ing the water throu the spray pond or the RHR heat exchanger, gh one Unit 2 shal l be OPERABLE:

a. In OPERATIONAL CONDITIONS l, 2, and 3, two subsystem s.

b. In OPERATIONAL CONDITIONS 4 and 5, the subsystem(s) systems and components required OPERABLE by Spec asso ciate d with 3.9.1 1.1, and 3.9.1 1.2. ifica tion 3.4.9 .2, APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, and 5.

ACTION:

a. In OPERATIONAL CONDITION l, 2, or 3:

1. With one RHRSW pump inoperable, resto re the inoperab OPERABLE statu s within 30 days, or be in at leas t le pump to within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTD HOT SHUTDOWN following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. OWN with in the

2. With one RHRSW pump in each subsystem inoperable, tJr 1 # 0-CU'rda;tt:.e leas t one of the inoperable RHRSW pumps to OPERABLEresto re at w,-f-h rA..e Fi"Jk w1 1n ays or be in at leas t HOT SHUTDOWN with in the statu s 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLO SHUTDOWN within the following next

z

n /r;rJ'l/leJ 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Cd~It:--fl ",., With one RHRSW subsystem otherwise inoperable, resto re the ino erable subs stem to OPERABLE statu s with at r,~ ?r~ra..""- j , ~ BLE RHRSW pump wit in 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> , unless otherwis leas t one in a) orb) below**, or be in at leas t HOT SHUTDOWN e spec ified next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the follo within the hours. wing 24 a) When the 'A' RHRSW subsystem is inoperable to allow repa irs of the 'A' RHRSW subsystem piping, with Limefor Generating Station Unit 1 shutdown, reac tor vesse rick removed and reactor cavi ty flooded, the 72-hour Allow l head Outage Time may be extended to 7 days once ed calendar year with the following compensatory meas r ever othe est ab 1i shed: ures

. _ /.  :.L.J_ __,H  ;:::o*

(:Jr ,- /? acc.P/""'qA..;-J (;. C:::. (A..;; T rJ 7 .f'U::.. J'-1,S.

~hr~ G::wrpleliM 17~~rt:M-

• • Only one of these two Actions, eithe r a.3.a ) or in a calendar year . However, *if eith er Unit 1 TSa.3.b ), may be entered on Unit 2 a.3.b ) has previously been entered in the calendar LCD 3.7.1 .1, Action a.3.a ) or a.3.a ) or a.3.b ) may not be entered during that sameyear, then Unit 2 Action calendar year.

LIMERICK - UNIT 2 3/4 7-1 Amendment No . .;w.,+Q.,~, 165

PLANT SYSTEMS.

I IMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

1) The following systems and subsystems will be protect ed in accordance with applicable station procedures:

• 'B' RHRSW subsystem

• ' B' ESW 1oop

• 'B' and 'D' RHB subsystems

• Dl2, 022, and 024 4kV buses and emergency diesel generators

• Division 2 and Division 4 Safeguard DC, and

2) The 'A' and 'B' loop of ESW return flow shall be aligned to the operable 'B' RHRSW return header only.

The ESW return valves to the 'B' RHRSW return header (i.e., HV-11-015A and HV-11-0158) will be admini strative ly control led in the open positio n and de-energized prior to entering the extended AOT. The ESW return valves to the 'A' RHRSW return header (i.e., HV-11-0llA and HV-11-0118) will be admini strative ly control led in the closed positio n and de-energized as part of the work boundary.

C?r in ~,...ela..~c.e When the 'B' RHRSW subsystem is inoperable to allow for

~,*r-A -r-M- P-s K repairs of the 'B' RHRSW subsystem piping, with Limerick Generating Station Unit 1 shutdown, reactor vessel head

..::z;;-,4,r/14 ~d' ~l'Nf'Je,,./;,"n removed and tor cavit flooded the 72-hour Allowed utage Time may be extended to 7 days once every other 77/#e ff °.f rt:u¢'1. calendar year with the following compensatory measures establi shed:

1) The following systems and subsystems will be protect ed in accordance with applicable station procedures:

• 'A' RHRSW subsystem

• ' A' ESW 1oop

• 'A' and 'C' RHR subsystems

• Dll, 021, and 023 4kV buses and emergency diesel generators

• Division 1 and Division 3 Safeguard DC, and

2) The 'A' and 'B' loop of ESW return flow shall be aligned to the operable 'A' RHRSW return header only.

The ESW return valves to the 'A' RHRSW return header (i.e., HV-11-0llA and HV-11-0llB) will be admini strative ly control led in the open positio n and de-energized prior to entering the extended AOT. The ESW return valves to the 'B' RHRSW return header (i.e., HV-11-015A and HV-11-0158) will be admini strative ly control led in the closed positio n and de-energized as part of the work boundary.

4. With both RHRSW subsystems otherwise inoperable, restore at least one subsystem to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN* within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

• Whenever both RHRSW subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practic al by use of alterna te heat removal methods.

LIMERICK - UNIT 2 3/4 7-la Amendment No . .;u,t,~.9fr. 165 I

PLANT SYSTEMS EMERGENCY SERVICE WATER SYSTEM - COMMON SYSTEM LIMITING CONDITION fOR OPERATION _

-Y3.7 .l.2 At least the following independent emergency service water system with each loop comprised of: loops,

a. Two OPERABLE emergency service water pumps, and

b. An OPERABLE flow path capable of taking suction from the emergency service water pumps wet pits which are supplied from the spray pond or the cooling tower basin and transfe rring the water to the assoc1ated Unit 2 and common safety -relate d equipment, shall be OPERABLE:

a. In OPERATIONAL CONDITIONS l, 2, and 3, two loops.

b. In OPERATIONAL CONDITIONS 4, 5, and*, one loop.

APP\ ICABJLITY: OP£RAT£0NAL CONDITIONS l, 2, 3, 4, 5, and *.

ACTION:

a. In OPERATION CONDITION 1, 2, or 3:

1. With one emergency service water pump inoper able, restore the inoper pump to OPERABLE status within 45 days or be in at least HOT SHUTDOWNable the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLO SHUTDOWN within the fo11ow*ing 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. within

2. With one emergency service water pump in each loop inoperable, restore least one inoperable pump to OPERABLE status within 30 days or be in at at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. the

3. With one emergency service water system loop otherwise inoper able, all equipment aligned to the inoperable loop inoperable**, restore declar e inoperable loop to OPERABLE status with at least one OPERABLE the hou ~or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> pump and within 72 in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

C>r- ; n ~n:/4PU'lce "'-';~.,4 77le ,E:-;s-k ~/,,.htJ C-4/hr-/e-h*~n 7~ R-CJ.fr-~ J

• When handling irradia ted fuel in the secondary containment.

• • The diesel genera tors may be aligned to the OPERABLE emergency service loop provided confirmatory flow testing has been performed. Those diesel water system not aligned to the OPERABLE emergency service water system loop shall be generators inoper able and the a~ns of 3.8.1.1 taken. declared

1. During the extended 7 Allowed Outage Time (AOT) specifi ed by TS LCO 3.7.1.1 , Action

a. 3.a) or a.3.b) to al ow for RHRSW subsystem piping repairs , the 72-hou

~abl ~ emergency service ~1ater system 1oop may al so be extende r AOT for one

' d to 7 days' for the same

_ j ' ~period. 0 ,., /-a ~r-da.nce.

w 1-.r-;, 't'llc:... ~le- '.Zrl/;r,.ned

&rn;> lef1P n /f,u.e ?i-1:15,_.~

LIMERICK - UNIT 2 3/4 7-3 Amendment Na . .ig,+.Q.,~ 155

PLANT SYSTEMS 3/4.7.3 .JlEACTOR CORE ISOLAflON CQOLING SYSTEM

) ~JMIIING.. COND1IJQN FOR OPERATION__ _

3.7.3 The reactor core isolatio n cooling <RCIC) system shall be OPERABLE with an OPERABLE flow path capable of automa tically taking suction from the suppression pool and transfe rring the water to the reactor pressur e vessel.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3 with reactor steam dome pressure greater than 150 osi g. ~ L / _ - ;1 /

. t::Jr /,., ~,..-~c.-e:.- ~,~.4 -rk-~ ~J/C" _.?.nl'-#rrH-~

ACT10N: U/H~/d°iPn 7J;ne . r:7~ret.H1

a. With the RCIC system inopera ble, operatio n may continue provided the HPCI s stem is OPERABLE; restore the RCIC system to OPERABLE status within 14 day: Otherwise, be in at least HOT SHUTDOWN within the next 12 and retuce reactor steam dome pressur e to less than or equal to 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> psig within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. DELETED

c. Specifi cation 3.0.4.b is not applica ble to RCIC.

SURVE I I I M:l..CL... R~Ol)i REt:JENTS 4.7.3 The RCIC system shall be demonstrated OPERABLE:

a. In accordance with the Surveil lance Frequency Control Program by:

1. Verifying location s suscept ible to gas accumulation are sufficie ntly filled with water.

2. Verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in positio n, is in its correct position .** I

3. Verifying that the pump flow control ler is in the correct position .

b. In accordance with the Surveil lance Frequency Control Program by verifyin g that the RCIC pump develops a flow of greater than or equal to 600 gpm in the test flow path with a system head corresponding to reactor vessel operatin g pressur e when steam is being supplied to the turbine at 1040 *J- 13, - 120 psig.*

• The provisi ons of Specifi cation 4.0.4 are not applicab le provided the surveil lance is performed 1vithin 12 r10urs after reactor' steam pressure is adequate to perform the test. If OPERABILITY is not success fully demonstrated within the 12-hour period, reduce reactor steam dome pressure to less than 150 psig within the following 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

• • Hot require d to be met for system vent flow paths opened under adminis trative control .

LIMERICK - UNIT 2

PLANT SYSTEMS 3/4.7 ,8 MAIN TURBINE BYPASS SYSTEM LIMITING CONDITION FOR OPERATION 3.7.8 The main turbin e bypass system shall be OPERABLE as determ number of operable main turbin e bypass valves being great er than ined by the speci fied in the CORE OPERATING LIMITS REPORT. or equal to that APPLICABILITY; OPERATIONAL CONDITION 1, when THERMAL POWER is equal to 25% of RATED THERMAL POWER. great er than or ACTION: With the main turbin e bypass system inope rable, restor OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or take the ACTION re uired b S e the system to 3.2.3 .c. CJlr /n ecific atio

~rc/~c.e:. ~;..,t-), ~he- /e/S

_ k

_;;:::-;,,4;-Atd ~ /e:.,t,~ -rJ"qee.. rF~:Jr~.:J 4.7.8 The main turbin e bypass system shall be demonstrated OPERAB with the Surve illanc e Frequency Control Program: LE in accordance

a. By cyclin g each turbin e bypass valve through at least one complete cycle of full trave l,

b. By performing a system functional test which includ es simulated actua tion, and by verify ing that each automatic valve actua automatic corre ct positi on, and tes to its

c. By determining TURBINE BYPASS SYSTEM RESPONSE TIME to be less than to the value speci fied in the CORE OPERATING LIMITS REPOR or equal I T.

LIMERICK - UNIT 2 3/4 7-33 Amendment No. J4, 147

3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES A.C. SOURCES - OPERATING LIMITING CONDITION FOR OPERATION 3.8.1.1 As a minimum, the following A.C. electrical power sources shall be OPERABLE:

a. Two physically independent circuits between the offsite transmission network and the onsite Class lE distribution system, and

b. Four separate and independent diesel generators, each with:

1. A separate day tank containing a minimum of 250 gallons of fuel,

2. A separate fuel storage system containing a minimum of 33,500 gallons of fuel, and

3. A separate fuel transfer pump.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION:

a. With one diesel generator of the above required A.C. electrical -p-ewe-r------

sources inoperable, demonstrate the OPERABILITY of the remaining A.C.

sources by performing Surveillance Requirement 4.8.1.1.1.a within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and at least once per 7 days thereafter. If the diesel generator became inoperable due to any cause other than an inoperable support system, an independently testable component, or preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining operable diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.4 for one diesel generator at a time, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unless the absence of any potential common-mode failure for the remaining diesel generators is determined. Restore the inoperable diesel generator to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See also ACTION e.

b. With two diesel generators of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C.

sources by performing Surveillance Requirement 4.8.1 . 1.1.a within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. If either of the diesel generators became inoperable due to any cause other than an inoperable support system, an independently testable component, or preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.4 for one diesel generator at a time, within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, unless the absence of any potential common-mode failure for the remaining diesel generators is det~rmined. Restore at least one of the inoperable diesel generators to OPERABLE status within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s* or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See also ACTION e.

• During the extended~Allowed Outage Time (AO!) specified by TS LCO 3.7.1.1, Action a.3.a) or a.3.b) to allow for RHRSW subsystem piping repairs, th 72-hour AOT f~o inoperable diesel generators may also be extended to 7 days for the same~period. -

• b ....L/_ ~* / /f * /

e>r ,;. ~,., "ce ,,v1-rn ri'J&. ,..~..SA:" ::z;,r1>/'#U&f C4" l~l!llh )"lAt111-- P~r~

LIMERICK - UNIT 2 8-1 Amendment No. ~. -+/--94, 165

ELECTRICAL POWER SYSTEMS I IMITING CQNDIIlON FOB OPEBATIQN (Cgnt1nygdl ACTION: (Cont 1nued)

c. With three diesel generators of the above required A.C. electr ical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C~ sources by performing Surveillance Requirement 4.8.l. l.l.a within l hour and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> therea fter; and perform Surveillance Requirement 4.8.1. 1.2.a. 4 for the remaining diesel generator, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> *. Restore at least one of the inoperable diesel generators to OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See also ACTION e.

d. With one offsit e*c1rc uit and one diesel generator of the A.C. electr ical power sources inoperable, demonstrate the above OPERAB required ILITY of the remaining A.C. sources by pe*rforming Surveillance Require ment 4.8.1. 1.1.a within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per B hours therea fter.

If the diesel generator became inoperable due to any cause other an inoperable support system, an 1ndependently testab le compo than preplanned preventive maintenance or testin g, demonstrate the nent, or OPERABILITY of the remaining diesel generators by performing Surveillance Requirement 4.8.1. 1.2.a. 4 for one diesel generator at a t1me, w1thin 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, unless the absence of any potential common -mode failure for the rema1n1ng diesel generators is determined. Restor least two offs1t e c1rcu1ts to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> rome time at of 1n1t1al loss or be in at least HOT SHUTDOWN within the next 1 ours and 1n COLD SHUTDOWN w1th1n the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.' See also ACTION e.

') c,.- /A ~rde'!t..,eCr;_ ~,-../-1,

Z:::-n /;r~ecl Ce>...-n//~~OH ~e ~_frevPtJ LIMERICK - UNIT 2 3/4 8-la Amendment No. 150

ELECTRICAL POWER SYSTEMS LIMITING CONQITION FOR OPERATION (Continued)

ACTION: (Continued)

e. In addition to the ACTIONS above:

1. For two train systems, with one or more dies~l ~enerators of the above required A.C. electrical power sources inoperable, verify within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter that at least one of the required two train system subsystem, train, components, and devices is OPERABLE and its associated diesel generator is OPERABLE. Otherwise, restore either the inoperable diesel generator or the inoperable system subsystem to an OPERABLE status within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s* or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. For the LPCI systems, with two or more diesel generators of the above required A.C. electrical power sources inoperable, verify within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> *thereafter that at least two of the required LPCI system subsystems, trains, components and devices are OPERABLE and its associated diesel generator is OPERABLE. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This ACTION does not apply for those systems covered in Specifications 3.7 . 1.1 and 3.7.1.2.

• During the extended~Allowed Outage Time (AOT) specified by TS LCO 3. 7.1.1, Action a.3.a) or a.3.b) to allow for RHRSW subsystem piping repairs, the 72 -hour AOT may also be extended to 7 days for the same~period.

t!:J r , *,., Oc..~r-c::IA.n t. e tAJ;-fJ, 1%e ,£4J:- I,,, Drhi e. j C,.t>hlp/e.,t-,&>n 7--:'Me ~ rA..n-LIMERICK - UNIT 2 3/4 8-2 Amendment No . 165

ELECTRICAL POWER SYSTEMS ACTION:

f. With one offsite circuit o t e a ove require A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C.

sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once pei 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. Restore at least two offsite circuits to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or e 1n a eas HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

With two of the above required offsite circuits inoperable, restore at least one of the,inoperable offsite circuits to OPERABLE status within our or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

With only one offsite circuit restored to OPERABLE status, restore at least two offsite circuits to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ro time of initial loss or be in at least HOT SHUTDOWN within tHe next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

h. With one offsite circuit and two diesel generators of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C~ sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. If either of the diesel generators became inoperable due to any cause other than an inoperable support system, an independently testable component, or preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining diesel generators by perf6rming Surveillance Requirement 4.8.1.1.2.a.4 for one diesel generator at a time, within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, unless the absence of any potential common-mode failure for the remaining diesel generators is determined. Restore at least one of the above required inoperable A.C. sources to OPERABLE status within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Restore at least two offsite circuits and at least three of the above required diesel generators to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from time of initial loss or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. See also ACTION e.

i. Specification 3.0.4.b is not applicable to diesel generators.

LIMERICK

• UNIT 2 3/4 8-2a Amendment No. ~. 150

ELECTRICAL POWER SYSTEMS 3/4.8.2 D.C. SOURCES D.C. SOURCES - OPERATING LIMITING *coNDI!ION FOR OPERAJION 3.B.2.1 As a minimum, the following O.C. electrical power sources shall be OPERABLE:

a. Division 1, Consisting of:

1. 125-Volt Battery 2Al C2AlD101).

2. 125-Volt Battery 2A2 C2A2Dl01).

3. 125-Volt Battery Charger 2BCA1 C2AlD103).

4. 125-Volt Battery Charger 2BCA2 C2A20103).

b. Division 2, Consisting of:

1. 125-Volt Battery 281 C281D101).

2. 125-Volt Battery 282 C2B2D101).

3. 125-Volt Battery Charger 2BCB1 (2810103).

4. 125-Volt Battery Charger 2BCB2 (2820103).

c. Division 3, Consisting of:

1. 125-Volt Battery 2C,C2CD101).

2. 125-Volt Battery Charger 2BCC C2CD103).

d. Division 4, Consisting of:

1. 125-Volt Battery 20 C2DD101).

2. 125-Volt Battery Charger 2BCD C2DD103).

APPLICABILITY:

~ or-OPERATIONAL CONDITIONS 1, 2, and 3. h. j ACTION: ;17 tk--~M ~"'7Ce- (,l:..J.1:-rh rite Ji?,,~} _z;: rrete Co6>?.P/t!!-r,,t)~ 7Tm.-c:::... ?r"'J,.....~

a. With one or wo a ery c argers on one 1v1s1on inoperable:

1. Restore battery terminal voltage to greater than or equal to the minimum establishe d float voltage within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />,

2. Verify associated Division 1 or 2 float currents 2 amps, or Division 3 or 4 float current s 1 amp within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafte r, and

3. Restore battery charger(s ) to OPERABLE status within 7 day

b. With one or more batteries inoperabl e due to:

1. One or two batteries on one division with one or more battery cells float voltage < 2.07 volts, perform 4.8.2.1.a .l and 4.8.2.1.a .2 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for affected battery(s ) and restore affected cell(s) voltage

~ 2.07 volts within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. Division 1 or 2 with float current> 2 amps. or with Division 3 or 4 with float current > 1 amp, perform 4.8.2.1.a .2 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for affected battery(s ) and restore battery float current to within limits 1 ~

within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. 1 LIMERICK - UNIT 2 3/4 8-10 Amendment No. 126

ELECTRICAL POWER SYSTEMS lJMITING CONDITION FOR OPERATION r)

• ' ACTION: (Continued)

3. One or two batteries on one division with one or more cells electrolyte level less than minimum established design limits, if electrolyte level was below the top of the plates restore electrolyte level to above top of plates within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and verify no evidence of leakage(*) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In all cases, restore electrolyte level to greater than or equal to minimum established design limits within 31 days.

4. One or two batteries on one division with pilot cell electrolyte temperature less than minimum established design limits, restore battery pilot cell temperature to greater than or equal to minimum established design limits within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

5. Batteries in more than one division affected, restore battery parameters for all batteries i~ all but one division to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

6. Ci) Any battery having both (Action b.l) one or more battery cells float voltage< 2.07 volts and (Action b.2) float current not within limits, and/or (ii) Any battery not meeting any Action b.1 through .b.5, Restore the battery parameters to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

c. With any battery(ies) on one division of the above required O.C. electrical power sources inoperable for reasons other than Action b., re tore the inoperable division battery to OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLO SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

?

",_ 1 ",, t:t.c~~~rlCC! ~~~A ~e- /c:--.s~ ~./;r/heJ CD~ /don ~e ff-e;~r-a.Ht

(*) Contrary to the prov1s1ons of Specification 3.0.2, if electrolyte level was below the top of the plates, the verification that there is no evidence of leakage is required to be completed regardless of when electrolyte level is restored.

LIMERICK - UNIT 2 3/4 8-lOa Amendment No. 126 I

ELECTRICAL POWER SYSTEMS

) APPLICABILITY: t:>r /n ~ra'~l!..e /,(.>,- ~

OPERATIONAL CONDITIONS 1,

~e ;i:?;'$1:: ~hrh'l-e.-~

ACTION:

u.t?"_p/~ 'eJ;; 77.l'he 8" ,,..~ J

a. With one of the above required Unit 2 A.C. dist divi sion s not energized, ribu tion system reenergize the divi sion within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at leas t HOT SHUTDOWN within the SHUTDOWN with next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD in the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With one of the above required Unit 2 D.C. dist divi sion s not energized, reenergize the divi ribu tion system in at leas t HOT SHUTDOWN within the next 12 sion within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> SHUTDOWN with in the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. hours and in COLD

c. With any of the above required Unit 1 and comm dist ribu tion system divi sion s not energized, on AC and/or DC common equipment inoperable, and take the appr declare the asso ciate d that system. opri ate ACTION for 4.8. 3.l Each of the above required power dist be determined energized in accordan with theribu tion system divi sion s shal l Program by veri fyin g corr ect breakerce alignmen Surv eilla nce Frequency Control busses/MCCs/panels. t and volt age on the LIMERICK

• UNIT 2 3/4 8-17 Amendment No. 147

AOMJNLS.IRAI!.v.£,CONJB.QL.S PROCEDURES AND PROGRAMS (Continued)

c. The program shall, as allowed by 10 CFR S0.55a, meet Subsection ISTA, "General Requirements," and Subsection lSTO, "Preservice and lnservice Examination and Testing of Dynamic Restraints (Snubbersl in Light-Water Reactor Nuclear Power Plants," in lieu of Section XI of the ASHE B&PV Code 151 requirements for snubbers, or meet authorized alternatives pursuant to 10 CFR 50 .55a.

d. The 120 -month program updates shall be made in accordance with 10 CFR 50.55a subject to the limitations and conditions listed therein.

1. Explosive Gas Monitoring Program This program provides controls for potentially explosive gas mixtures contained downstream of the off-gas recombiners.

The program shall include:

a. The limit for the concentration of hydrogen downstream of the offgas recombiners and a surveillance program to ensure the limit is maintained. This limit shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);

The provisions of SR 4. 0.2 and SR 4.0.3 are applicable to the Explosive Gas Monitoring Program surveillance frequencies.

LIMERICK - UNIT 2 6-14e Amendment No. +g.4, 191

LGS TS MARKUP INSERT LGS TS 6.8.4.m INSERT

m. 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-A, Revision 0, "Risk-Managed Technical Specifications (RMTS) Guidelines." The program shall include the following:

a. The RICT may not exceed 30 days.

b. A RICT may only be utilized in OPERATIONAL CONDITIONs 1 and 2.

c. When a RICT is being used, any change to the plant configuration, as defined in NEI 06-09-A, Appendix 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 ACTION allowed outage time (i.e., not the RICT) or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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 ACTION allowed outage 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 approved for use with this program in Amendment Nos. [XXX/YYY], or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.

ATTACHMENT 3 License Amendment Request Limerick Generating Station, Units 1 and 2 Docket Nos. 50-352 and 50-353 Response to Request for Additional Information License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b."

Information Supporting Instrumentation Redundancy and Diversity

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Attachment 3 Docket Nos. 50-352 and 50-353 Page 1 of 15 Limerick RPS SCRAM Instrumentation TS Table 3.3.1-1 Diversity TS Table RPS Instrumentation Function Credited Safety Analysis Event Event Diverse RPS Instrumentation (*)

TABLE 3.3.1-1 1. Intermediate Range Monitors(b):

a. Neutron Flux - High None (RBM Credited) AOO Manual SCRAM (Pushbuttons or Reactor MODE Switch)

b. Inoperative None (RBM Credited) AOO Manual SCRAM TABLE 3.3.1-1 2. Average Power Range Monitor:

a. Neutron Flux - Upscale (Setdown) None (RBM Credited) AOO Manual SCRAM

b. Simulated Thermal Power - Upscale None AOO Manual SCRAM

c. Neutron Flux - Upscale Abnormal Startup of Idle Recirculation Pump AOO Manual SCRAM Recirculation Flow Control Failure - Increasing Flow AOO Manual SCRAM

d. Inoperative Same as 2.c. Manual SCRAM

e. 2-Out-Of-4 Voter Same as 2.c. Manual SCRAM

f. OPRM Upscale Core Thermal Hydraulic Instability Manual SCRAM TABLE 3.3.1-1 3. Reactor Vessel Steam Dome Pressure - High Loss of Stator Cooling AOO Neutron Flux Upscale/Manual SCRAM TABLE 3.3.1-1 4. Reactor Vessel Water Level - Low, Level 3 Loss of All Feedwater Flow AOO Manual SCRAM FWLB Outside Primary Containment DBA Manual SCRAM TABLE 3.3.1-1 5. Main Steam Line Isolation Valve-Closure MSIV Closure AOO RPV High Pressure /Neutron Flux Upscale/ Manual SCRAM MSLB Outside Primary Containment DBA Low RPV Level 3/Manual SCRAM TABLE 3.3.1-1 6. DELETED TABLE 3.3.1-1 7. Drywell Pressure - High LOCA DBA Low RPV Level 3/ Manual SCRAM TABLE 3.3.1-1 8. Scram Discharge Volume Water Level - High

a. Level Transmitter None None Float Switch/Manual SCRAM

b. Float Switch None None Level Transmitter/Manual SCRAM TABLE 3.3.1-1 9. Turbine Stop Valve - Closure Feedwater Max Demand Controller Failure AOO RPV High Pressure /Neutron Flux Upscale/TCV Closure LS/ Manual SCRAM Pressure Regulator Fails Open AOO RPV High Pressure /MSIV Closure LS/TCV Closure LS/Manual SCRAM Turbine Trip AOO RPV High Pressure /Neutron Flux Upscale/TCV Closure LS/Manual SCRAM Loss of Condenser Vacuum AOO RPV High Pressure /Neutron Flux Upscale/MSIV Closure LS/TCV Closure LS/ Manual SCRAM Both Recirculation Pumps Trip AOO RPV High Pressure/TCV Closure LS/Manual SCRAM TABLE 3.3.1-1 10. Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Generator Trip or Load Rejection AOO RPV High Pressure /Neutron Flux Upscale/TSV Closure LS/ Manual SCRAM Loss of AC Power (LOOP) AOO RPV High Pressure /Neutron Flux Upscale/TSV Closure LS/ Manual SCRAM Failure of RHR Shutdown Cooling DBA RPV High Pressure /Neutron Flux Upscale/TSV Closure LS/ Manual SCRAM TABLE 3.3.1-1 11. Reactor Mode Switch Shutdown Position None N/A Manual SCRAM Pushbuttons

12. Manual Scram None N/A Reactor Mode Switch

(*) The Redundant Reactivity Control System (RRCS) Alternate Rod Insertion Function (ARI) Provides Automatic RPS System Level Diversity. (UFSAR Sections 7.6.1.8 and 15.8. Table 7.6-5.)

This Diverse RPS Backup System will SCRAM all control rods on either High Reactor Pressure or Low Low (L2) Reactor Level for Instrument Functions 3.,4.,5.,7.,9., and 10.

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Attachment 3 Docket Nos. 50-352 and 50-353 Page 2 of 15 LIMERICK RPS SCRAM INSTRUMENTATION UFSAR REFERENCES & TRIP FUNCTIONS Initiating Events: Credited RPS Automatic Instrumentation Function: Diverse RPS Automatic or Manual Instrumentation:

UFSAR Transient and/or Accident RPV High RPV Low APRM TSV Fast TCV Fast MSIV Drywell High RPV High RPV Low APRM TSV Fast TCV Fast MSIV Manual Section Pressure Water Level High Neutron Closure Closure Closure Pressure Pressure Water Level High Neutron Closure Closure Closure SCRAM (L3) Flux Limit Switch Limit Switch Limit Switch (L3) Flux LS LS LS Decrease in Reactor Coolant Temperature:

15.1.2 Feedwater Max Demand Controller Failure X X X X X 15.1.3 Pressure Regulator Fails Open X X X X X Increase in Reactor Vessel Pressure:

15.2.2 Generator Trip or Load Rejection X X X X X 15.2.3 Turbine Trip X X X X X 15.2.4 MSIV Closure X X X X 15.2.5 Loss of Condenser Vacuum X X X X X X 15.2.6 Loss of AC Power (LOOP) X X X X X 15.2.7 Loss of All Feedwater Flow X X 15.2.9 Failure of RHR Shutdown Cooling X X X X X 15.2.10 Loss of Stator Cooling X X X Decrease In Reactor Coolant System Flow Rate:

15.3.1 Both Recirculation Pumps Trip X X X X Reactivity and Power Distribution Anomalies:

15.4.4 Abnormal Startup of Idle Recirculation Pump X X 15.4.5 Recirculation Flow Control Failure - Increasing Flow X X Decrease in Reactor Coolant Inventory:

15.6.4 MSLB Outside Primary Containment X X X 15.6.5 LOCA X X X X 15.6.6 FWLB Outside Primary Containment X X OTHER LIMERICK UFSAR

REFERENCES:

7.2.2 Reactor Protection System (RPS)

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Isolation Actuation Instrumentation TS Table 3.3.21 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 3 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation

1. MAIN STEAM LINE ISOLATION 1. MAIN STEAM LINE ISOLATION TABLE 3.3.21

a. Reactor Vessel Water Level

1) Low, LowLevel 2 LOCA (UFSAR Section 15.6.5) DBA Manual Initiation to Close (Normally Closed) Main Steam Sample PCIV's

2) Low, Low, LowLevel 1 LOCA (UFSAR Section 15.6.5) DBA Main Steam Line Low Pressure/Manual Initiation to Close MSIV's & Normally Closed MSL Drain PCIV's

b. DELETED

c. Main Steam Line Pressure Low Pressure Regulator Fails Open AOO Manual Initiation to Close MSIV's & Normally Closed MSL Drain PCIV's (UFSAR Section 15.1.3)

d. Main Steam Line Flow High MSLB Outside Primary Containment DBA Outboard MSIV Room High Temperature/Turbine Enclosure Main Steam Line Tunnel (UFSAR Section 15.6.4) High Temperature/ Manual Initiation to Close MSIV's & Normally Closed MSL Drain PCIV's

e. Condenser Vacuum Low Loss of Condenser Vacuum AOO Manual Initiation to Close MSIV's & Normally Closed MSL Drain PCIV's (UFSAR Section 15.2.5)

f. Outboard MSIV Room Temperature High MSLB Outside Primary Containment DBA Main Steam Line High Flow /Manual Initiation to Close MSIV's & Normally Closed MSL (UFSAR Section 15.6.4) Drain PCIV's

g. Turbine Enclosure Main Steam Line Tunnel Temperature High MSLB Outside Primary Containment DBA Main Steam Line High Flow /Manual Initiation to Close MSIV's & Normally Closed MSL (UFSAR Section 15.6.4) Drain PCIV's

h. Manual Initiation None N/A N/A

2. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION 2. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION TABLE 3.3.21

a. Reactor Vessel Water Level Low Level 3 None. Unanticipated RPV Water Inventory N/A Manual Initiation to Close RHR SDC PCIV's if RHR is Operating In the SDC Mode To Isolate Loss Isolates System. a Possible RPV Inventory Loss Source.

None. RPV Flow Diversion to Radwaste N/A High Drywell Pressure/Manual Closure to Prevent RHR System Flow Diversion None. RHR System Sample Valves N/A High Drywell Pressure/Manual Closure if Sampling.

b. Reactor Vessel (RHR CutIn Permissive) Pressure High Prevent RHR System Overpressurization. ISLOCA Manual Initiation to Close RHR SDC PCIV's if RHR is Operating.

(UFSAR Section 7.6.1.2)

c. Manual Initiation None N/A N/A

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Isolation Actuation Instrumentation TS Table 3.3.21 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 4 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation

3. REACTOR WATER CLEANUP SYSTEM ISOLATION 3. REACTOR WATER CLEANUP SYSTEM ISOLATION TABLE 3.3.21

a. RWCS Differential Flow High RWCU Pipe Break HELB RWCU Area High Temperature/RWCU Area Ventilation High Differential (UFSAR Section 3.6.1 and Table 3.61) Temperature/Reactor Vessel Low Water Level Level 2/ Manual Initiation to Close RWCU PCIV's

b. RWCS Area Temperature High RWCU Pipe Break HELB RWCU High Differential Flow/RWCU Area Ventilation High Differential (UFSAR Section 3.6.1 and Table 3.61) Temperature/Reactor Vessel Low Water Level Level 2/ Manual Initiation to Close RWCU PCIV's

c. RWCS Area Ventilation Differential Temperature High RWCU Pipe Break HELB RWCU High Differential Flow/RWCU Area High Temperature/Reactor Vessel Low Water (UFSAR Section 3.6.1 and Table 3.61) Level Level 2/ Manual Initiation to Close RWCU PCIV's

d. SLCS Initiation Isolate RWCU During RRCS SLCS Initiation ATWS Manual Initiation to Close RWCU PCIV's For SLCS Initiation (UFSAR Sections 9.3.5 & 15.8)

e. Reactor Vessel Water Level Low, Low Level 2 LOCA (UFSAR Section 15.6.5) DBA Manual Initiation to Close RWCU PCIV's & Normally Closed RWCU Sample PCIV's

f. Manual Initiation None N/A N/A

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Isolation Actuation Instrumentation TS Table 3.3.21 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 5 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION 4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION TABLE 3.3.21

a. HPCI Steam Line Differential Pressure (Flow) High HPCI Pipe Break HELB Functions 4 b., 4 d., 4 e., and 4 f./ Manual Initiation to Close HPCI PCIV's (UFSAR Section 3.6.1 and Table 3.61)

b. HPCI Steam Supply Pressure Low Auto Closes Steam Supply & Vac Bkr. PCIV's. LOCA Manual Initiation to Stop HPCI System Operation by Closing HPCI PCIV's Isolates HPCI Due to Lack of Motive Steam Pressure to Effectively Function.

(UFSAR Section 6.2 & Table 6.217)

c. HPCI Turbine Exhaust Diaphragm Pressure High Isolates HPCI for Leakage and Equipment None Functions 4 b., 4 d., 4 e., and 4 f./Manual Initiation to Close HPCI PCIV's Protection (UFSAR Section 7.3.1.1.2.4.12)

d. HPCI Equipment Room Temperature High HPCI Pipe Break HELB Functions 4 a., 4 b., 4 e., and 4 f./Manual Initiation to Close HPCI PCIV's (UFSAR Section 3.6.1 and Table 3.61)

e. HPCI Equipment Room Differential Temperature High HPCI Pipe Break HELB Functions 4 a., 4 b., 4 d., and 4 f./Manual Initiation to Close HPCI PCIV's (UFSAR Section 3.6.1 and Table 3.61)

f. HPCI Pipe Routing Area Temperature High HPCI Pipe Break HELB Functions 4 a., 4 b., 4 d., and 4 e./Manual Initiation to Close HPCI PCIV's (UFSAR Section 3.6.1 and Table 3.61)

g. Manual Initiation None N/A N/A

h. HPCI Steam Line Differential Pressure Timer HPCI Pipe Break Spurious Trip Avoidance HELB Functions 4 b., 4 d., 4 e., and 4 f./ Manual Initiation to Close HPCI PCIV's (UFSAR Sections 3.6.1 & 7.3.1.1.1.1.3)

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Isolation Actuation Instrumentation TS Table 3.3.21 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 6 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation

5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION TABLE 3.3.21 RCIC Pipe Break HELB Functions 5 b., 5d., 5 e., and 5 f./ Manual Initiation to Close RCIC PCIV's

a. RCIC Steam Line Differential Pressure (Flow) High (UFSAR Section 3.6.1 and Table 3.61)

Auto Closes Steam Supply & Vac Bkr. PCIV's. LOCA Manual Initiation to Stop RCIC System Operation by Closing RCIC PCIV's Isolates RCIC Due to Lack of Motive Steam

b. RCIC Steam Supply Pressure Low Pressure to Effectively Function.

(UFSAR Section 6.2 & Table 6.217)

Isolates RCIC for Leakage and Equipment None Functions 5 b., 5 d., 5 e., and 5 f./Manual Initiation to Close RCIC PCIV's

c. RCIC Turbine Exhaust Diaphragm Pressure High Protection (UFSAR Section 7.3.1.1.2.4.13)

RCIC Pipe Break HELB Functions 5 a., 5 b., 5 e., and 5 f./Manual Initiation to Close RCIC PCIV's

d. RCIC Equipment Room Temperature High (UFSAR Section 3.6.1 and Table 3.61)

RCIC Pipe Break HELB Functions 5 a., 5 b., 5 d., and 5 f./Manual Initiation to Close RCIC PCIV's

e. RCIC Equipment Room Differential Temperature High (UFSAR Section 3.6.1 and Table 3.61)

RCIC Pipe Break HELB Functions 5 a., 5 b., 5 d., and 5 e./Manual Initiation to Close RCIC PCIV's

f. RCIC Pipe Routing Area Temperature High (UFSAR Section 3.6.1 and Table 3.61)

g. Manual Initiation None N/A N/A

h. RCIC Steam Line Differential Pressure Timer RCIC Pipe Break Spurious Trip Avoidance HELB Functions 5 b., 5 d., 5 e., and 5 f./ Manual Initiation to Close RCIC PCIV's (UFSAR Sections 3.6.1 & 7.4.1.1.3.2)

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Isolation Actuation Instrumentation TS Table 3.3.21 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 7 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation

6. PRIMARY CONTAINMENT ISOLATION 6. PRIMARY CONTAINMENT ISOLATION TABLE 3.3.21

a. Reactor Vessel Water Level

1) Low, LowLevel 2 LOCA (UFSAR Section 15.6.5) DBA Group I RPV Coolant Sample Valves Manual Initiation to Close (Normally Closed) Sample PCIV's Group 6 Primary Containment Purge/N2 Inerting Systems/Rad Functions 6.b.,6.e.,7.c.1.&2./ Manual to Close PCIV's Monitoring/Containment Sampling Group 7 Primary Containment Instrument Gas/TIP Nitrogen Purge Functions 6.b.,6.e./ Manual to Close PCIV's Group 8 Drywell Equipment/Floor Drain System/TIP Retraction/SP Cleanup Functions 6.b/Manual to Close PCIV's

2) Low, Low, LowLevel 1 LOCA (UFSAR Section 15.6.5) DBA Group 7 Primary Containment Instrument Gas/TIP Nitrogen Purge Functions 6.b.,6.e./ Manual to Close PCIV's Group 8 Drywell Chilled Water/Reactor Enclosure Cooling Water Function 6.b./ Manual to Close PCIV's

b. Drywell Pressure High LOCA (UFSAR Section 15.6.5) DBA Group 6 Primary Containment Purge/N2 Inerting System/Rad Functions 6.a.1),6.e.,7.c.1.&2./Manual to Close PCIV's Monitoring/Containment Sampling Group 7 Primary Containment Instrument Gas Functions 6.a.2),6.e./Manual to Close PCIV's TIP Nitrogen Purge Functions 6.a.1),6.e./Manual to Close PCIV's Group 8 Drywell Chilled Water/Reactor Enclosure Cooling Water Function 6.a.2)/Manual to Close PCIV's Drywell Equipment/Floor Drain System/TIP Retraction/SP Cleanup Function 6.a.1)/Manual to Close PCIV's

c. North Stack Effluent Radiation High LOCA (UFSAR Section 15.6.5) DBA Group 6 Primary Containment Purge/N2 Inerting System Functions 6.a.1),6.b.,6.e.,7.c.1.&2./Manual to Close PCIV's

d. Deleted

e. Reactor Enclosure Ventilation Exhaust DuctRadiation High LOCA (UFSAR Section 15.6.5) DBA Group 6 Primary Containment Purge/N2 Inerting Systems/Rad Functions 6.a.1),6.b.,7.c.1.&2./Manual to Close PCIV's Monitoring/Containment Sampling Group 7 Primary Containment Instrument Gas Functions 6.a.2),6.b/Manual to Close PCIV's TIP Nitrogen Purge Functions 6.a.1),6.b/Manual to Close PCIV's

f. Deleted

g. Deleted

h. Drywell Pressure High/Reactor Pressure Low LOCA (UFSAR Section 15.6.5) DBA Manual to Close Normally Closed CS Test Return PCIV's & RHR SP Spray PCIV's

i. Primary Containment Instrument Gas Line to Drywell DP Low LOCA (UFSAR Section 15.6.5) DBA Manual to Close PCIG To ADS PCIV's

j. Manual Initiation None N/A N/A

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 LIMERICK NSSSS/ISOLATION INSTRUMENTATION UFSAR EVENTS and TRIP FUNCTIONS Attachment 3 Docket Nos. 50-352 and 50-353 Page 8 of 15 Credited Automatic Instrumentation Function:

Event LOCA LOCA LOCA MSLB MSLB LOCA LOCA HELB HELB LOCA HELB LOCA LOCA AOO AOO FHA LOCA ISLOCA LOCA ATWS Trip Signal Letter A B C E F G H J K KA L LA M P Q R S V W Y NSSSS Function RPV Low RPV Low RPV Low MSL MSL ECCS Drywell RWCU RCIC RCIC Low HPCI HPCI Low ADS MSIV MSIV Low Refuel Reactor RHR North RWCU Group Water Water Water High High Area Isolation High Line Line Steam Line Steam Instr Gas Low MSL Condenser Area Enclosure SDC High Stack SLC Level (L3) Level (L2) Level (L1) Flow Temp (C&H) Pressure Break Break Pressure Break Pressure Isolation Pressure Vacuum High Rad High Rad RPV Pres High Rad Isolation MAIN STEAM LINE ISOLATION: (RCPB Breach/Leak, EHC Pressure Control Failure, Loss of the Primary Heat Sink (Main Condenser))

ONE IA MSIV's X X X X X MSL Drain MOVs X X X X X IB MSL Sample AOVs X RHR SDC MODE ISOLATION: (Isolates the RHR SDC Lines to Remove a Potential RPV Leakage Source and Protect the Low Pressure RHR Piping.)

TWO SDC Suction and Injection IIA MOVs/Injection Testable Check X X Valves & Their Bypass AOV's RHR Discharge to Radwaste MOVs IIA X X and RHR Sample AOV's RWCU SYSTEM ISOLATION: (RWCU System Leak Isolation and Isolate RWCU Upon a Standby Liquid Control (SLC) System Initiation Signal.)

THREE III RWCU Suction MOVs X X X HPCI SYSTEM ISOLATION ( HPCI System Leak Isolation and Isolate HPCI System via PCIV's Due to Lack of Motive Steam Pressure to Effectively Function.)

FOUR IV HPCI Steam Line MOVs X X RCIC SYSTEM ISOLATION (RCIC System Leak Isolation and Isolate RCIC System via PCIV's Due to Lack of Motive Steam Pressure to Effectively Function.)

FIVE V RCIC Steam Line MOVs X X

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 LIMERICK NSSSS/ISOLATION INSTRUMENTATION UFSAR EVENTS and TRIP FUNCTIONS Attachment 3 Docket Nos. 50-352 and 50-353 Page 9 of 15 Credited Automatic Instrumentation Function:

Event LOCA LOCA LOCA MSLB MSLB LOCA LOCA HELB HELB LOCA HELB LOCA LOCA AOO AOO FHA LOCA ISLOCA LOCA ATWS Trip Signal Letter A B C E F G H J K KA L LA M P Q R S V W Y NSSSS Function RPV Low RPV Low RPV Low MSL MSL ECCS Drywell RWCU RCIC RCIC Low HPCI HPCI Low ADS MSIV MSIV Low Refuel Reactor RHR North RWCU Group Water Water Water High High Area Isolation High Line Line Steam Line Steam Instr Gas Low MSL Condenser Area Enclosure SDC High Stack SLC Level (L3) Level (L2) Level (L1) Flow Temp (C&H) Pressure Break Break Pressure Break Pressure Isolation Pressure Vacuum High Rad High Rad RPV Pres High Rad Isolation PRIMARY CONTAINMENT PURGE/N2 INERTING SYSTEMS/RAD MONITORING/CONTAINMENT SAMPLING: (Isolate a Primary/Secondary Contaiment Leakage Path to the Enviroment.)

SIX Drywell & Suppression Pool Air Purge/Drywell & Suppression Pool VIA Nitrogen Purge/Drywell & X X X X X Suppression Pool Purge to SGT (11 Valves Total)

Drywell & Suppression Pool Purge to Equipment VIB Compartment/Nitrogen Inerting X X X X Block Valves (6 Valves Total)

Drywell/Suppression Pool Sampling/ Drywell Rad Monitors/

VIC Small Nitrogen Makeup/ H2 X X X X Recombiner Valves (29 Valves Total)

PRIMARY CONTAINMENT INSTRUMENT GAS: (Isolates A Potential Primary Containment LOCA Leakage Path.)

SEVEN Primary Containment Instrument VIIA Gas Lines X X X (5 Valves Total)

VIIB TIP Purge Tube (1 Valve) X X X VIIC ADS Valves Instrument Gas X DRYWELL CHILLED WATER/REACTOR ENCLOSURE COOLING WATER/DRYWELL EQUIPMENT/FLOOR DRAIN SYSTEM/TIP RETRACTION/SP CLEANUP: (Isolates Potential Primary Containment LOCA Leakage Path.)

EIGHT DWCW and RECW Isolation Valves VIIIA X X (12 Valves Total)

Drywell Equipment and Floor Drain Valves/ Tip Guide Tubes/

VIIIB X X Suppression Pool Cleanup (11 Valves Total)

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Emergency Core Cooling System Actuation Instrumentation TS Table 3.3.3-1 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 10 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation LOW PRESSURE ECCS INJECTION SYSTEMS:

1. CORE SPRAY SYSTEM: 1. CORE SPRAY SYSTEM:

TABLE 3.3.3-1

a. Reactor Vessel Water Level - Low Low Low, Level 1 LOCA DBA Functions 1b. and 1c./Manual CS System Initiation & EDG Start.

b. Drywell Pressure - High LOCA DBA Function 1a./Manual CS System Initiation & EDG Start.

c. Reactor Vessel Pressure - Low (Permissive) LOCA DBA Function 1a./Manual CS System Initiation & EDG Start.

Prevent CS System Overpressurization ISLOCA Redundant Function 1c. ( 1 out of 2) for CS Loop Injection Valve Permissive.

d. Manual Initiation None N/A N/A

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM: 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM:

TABLE 3.3.3-1

a. Reactor Vessel Water Level - Low Low Low, Level 1 LOCA DBA Functions 1b. and 1c./Manual LPCI Initiation.

b. Drywell Pressure - High LOCA DBA Function 1a./Manual LPCI Initiation.

c. Reactor Vessel Pressure - Low (Permissive) LOCA DBA Function 1a./Manual LPCI Initiation.

d. Injection Valve Differential Pressure-Low (Permissive) Prevent RHR System Overpressurization ISLOCA Other Three Independent LPCI Trains Provide System Level Redundancy.

e. Manual Initiation None N/A N/A LIMERICK UFSAR

REFERENCES:

UFSAR Core Spray/LPCI UFSAR Event Section Description Section 6.3 Emergency Core Cooling Systems 7.6.1.2 High Pressure/Low Pressure Systems Interlocks 15.2.9 Failure of RHR Shutdown Cooling (Credits No Automatic Action) 15.6.4 MSLB Outside Primary Containment 15.6.5 LOCA 15.6.6 FWLB Outside Primary Containment

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Emergency Core Cooling System Actuation Instrumentation TS Table 3.3.3-1 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 11 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation HIGH PRESSURE ECCS INJECTION SYSTEMS:

3. HIGH PRESSURE COOLANT INJECTION SYSTEM: 3. HIGH PRESSURE COOLANT INJECTION SYSTEM:

TABLE 3.3.3-1

a. Reactor Vessel Water Level - Low Low, Level 2 LOCA DBA Function 1b./Manual HPCI Initiation. ADS Provides System Level Redundancy High Pressure RPV Coolant Injection Source AOO Manual HPCI Initiation. RCIC Provides System Level Redundancy

b. Drywell Pressure - High LOCA DBA Function 1a./Manual HPCI Initiation. ADS Provides System Level Redundancy

c. Condensate Storage Tank Level - Low High Pressure RPV Coolant Injection System AOO Manual HPCI Suction Transfer from CST to Suppression Pool.

Initial Water Source. Auto Transfers Water DBA Source to Suppression Pool When CST Water Inventory is Low or During A Seismic Event.

d. Suppression Pool Water Level - High Limits Volume of Water Added to Suppression AOO Manual HPCI Suction Transfer from CST to Suppression Pool.

Pool to Prevent Excessive Containment Loads. DBA

e. Reactor Vessel Water Level - High, Level 8 Prevents Overfilling RPV and Flooding Main AOO Manual HPCI Trip.

Steam Lines. DBA

f. Manual Initiation None N/A N/A LIMERICK UFSAR

REFERENCES:

UFSAR HPCI UFSAR Event Section Description Section 6.3 Emergency Core Cooling Systems 15.1.2 Feedwater Max Demand Controller Failure 15.1.3 Pressure Regulator Fails Open 15.2.4 MSIV Closure 15.2.5 Loss of Condenser Vacuum 15.2.6 Loss of AC Power (LOOP) 15.2.7 Loss of All Feedwater Flow 15.3.1 Both Recirculation Pumps Trip 15.6.4 MSLB Outside Primary Containment 15.6.5 LOCA 15.6.6 FWLB Outside Primary Containment

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Emergency Core Cooling System Actuation Instrumentation TS Table 3.3.3-1 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 12 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation HIGH PRESSURE ECCS INJECTION SYSTEMS:

4. AUTOMATIC DEPRESSURIZATION SYSTEM: 4. AUTOMATIC DEPRESSURIZATION SYSTEM:

TABLE 3.3.3-1

a. Reactor Vessel Water Level - Low Low Low, Level 1 LOCA DBA Redundant Division Trip System Initiates ADS Valve Actuation.

b. Drywell Pressure - High LOCA DBA Redundant Division Trip System Initiates ADS Valve Actuation.

c. ADS Timer LOCA DBA Redundant Division Trip System Initiates ADS Valve Actuation.

d. Core Spray Pump Discharge Pressure - High (Permissive) LOCA DBA Function e./Redundant Division Trip System Initiates ADS Valve Actuation.

e. RHR LPCI Mode Pump Discharge Pressure - High (Permissive) LOCA DBA Function d./Redundant Division Trip System Initiates ADS Valve Actuation.

f. Reactor Vessel Water Level - Low, Level 3 (Permissive) LOCA DBA Redundant Division Trip System Initiates ADS Valve Actuation.

g. Manual Initiation None N/A Manual ADS Initiation with Function d. or e. Operable

h. ADS Drywell Pressure Bypass Timer Piping Break Outside Containment DBA Redundant Division Trip System Initiates ADS Valve Actuation.

LIMERICK UFSAR

REFERENCES:

UFSAR ADS UFSAR Event Section Description Section 6.3 Emergency Core Cooling Systems 15.6.4 MSLB Outside Primary Containment 15.6.5 LOCA

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Attachment 3 Docket Nos. 50-352 and 50-353 Page 13 of 15 Limerick Recirculation Pump Trip Actuation Instrumentation TS Tables 3.3.4 Diversity Table TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION: ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION:

TABLE 3.3.4-1

1. Reactor Vessel Water Level - Low Low, Level 2 RRCS Trips Both Reactor Recirculation Pumps ATWS Function 2./Manually Trip Both Reactor Recirculation Pumps by MCR Handswitch via (UFSAR Sections 7.6 and 15.8. Table 7.6-5.) EOC Trip Coils/Manually Trip Both Reactor Recirculation Pumps by RRCS MCR Manual Initiation.

2. Reactor Vessel Pressure - High RRCS Trips Both Reactor Recirculation Pumps ATWS Function 1./Manually Trip Both Reactor Recirculation Pumps by MCR Handswitch via (UFSAR Sections 7.6 and 15.8. Table 7.6-5.) EOC Trip Coils/Manually Trip Both Reactor Recirculation Pumps by RRCS MCR Manual Initiation.

END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION: END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION:

TABLE 3.3.4-2

1. Turbine Stop Valve - Closure Reduces Severity of UFSAR Chapter 15 Reactor Fast AOO Function 2./Manually Trip Both Reactor Recirculation Pumps by MCR Handswitch via Pressurization Transient Events on Nuclear Fuel EOC Trip Coils/Apply MCPR Penalty Per the COLR. This is an Approved Compensatory Cladding Integrity (Fuel Thermal Margin MCPR). It Measure When the End-Of-Cycle Recirculation Pump Trip (EOC-RPT) System Is Supplements the Reactor Scram Function During Inoperative (OOS).

These Events.

2. Turbine Control Valve-Fast Closure Reduces Severity of UFSAR Chapter 15 Reactor Fast AOO Function 1./Manually Trip Both Reactor Recirculation Pumps by MCR Handswitch via Pressurization Transient Events on Nuclear Fuel EOC Trip Coils/Apply MCPR Penalty Per the COLR. This is an Approved Compensatory Cladding Integrity (Fuel Thermal Margin MCPR). It Measure When the End-Of-Cycle Recirculation Pump Trip (EOC-RPT) System Is Supplements the Reactor Scram Function During Inoperative (OOS).

These Events.

LIMERICK UFSAR

REFERENCES:

UFSAR End-Of-Cycle Recirculation Pump Trip UFSAR Event Section Section Description 7.7.1.3 Recirculation Flow Control System 15.1.2 Feedwater Max Demand Controller Failure 15.1.3 Pressure Regulator Fails Open 15.2.2 Generator Trip or Load Rejection 15.2.3 Turbine Trip 15.2.5 Loss of Condenser Vacuum 15.2.6 Loss of AC Power (LOOP) 15.2.7 Loss of All Feedwater Flow 15.2.9 Failure of RHR Shutdown Cooling

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Reactor Core Isolation Cooling System Actuation Instrumentation TS Table 3.3.5-1 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 14 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation REACTOR CORE ISOLATION COOLING SYSTEM: REACTOR CORE ISOLATION COOLING SYSTEM:

TABLE 3.3.5-1

a. Reactor Vessel Water Level - Low Low, Level 2 High Pressure RPV Coolant Injection Source AOO Manual RCIC Initiation. HPCI Provides System Level Redundancy

b. Reactor Vessel Water Level - High, Level 8 Prevents Overfilling RPV and Flooding Main AOO Manual RCIC Trip.

Steam Lines.

c. Condensate Storage Tank Level - Low High Pressure RPV Coolant Injection System AOO Manual RCIC Suction Transfer from CST to Suppression Pool.

Initial Water Source. Auto Transfers Water Source to Suppression Pool When CST Water Inventory is Low or During A Seismic Event.

d. Manual Initiation None N/A N/A LIMERICK UFSAR

REFERENCES:

UFSAR RCIC UFSAR Event Section Description Section 5.4.6 Reactor Core Isolation Cooling System 15.1.2 Feedwater Max Demand Controller Failure 15.1.3 Pressure Regulator Fails Open 15.2.4 MSIV Closure 15.2.5 Loss of Condenser Vacuum 15.2.6 Loss of AC Power (LOOP) 15.2.7 Loss of All Feedwater Flow 15.3.1 Both Recirculation Pumps Trip 15.6.4 MSLB Outside Primary Containment 15.6.5 LOCA (Not ECCS. Operates but Not Credited.)

15.6.6 FWLB Outside Primary Containment

Response to Request for Additional Information LAR to Adopt TSTF-505, Rev. 2 Limerick Feedwater/Main Turbine Trip System Actuation Instrumentation Table 3.3.9-1 Diversity Table Attachment 3 Docket Nos. 50-352 and 50-353 Page 15 of 15 TS Table Isolation Instrumentation Function Credited Safety Analysis Event Event Diverse Isolation Instrumentation FEEDWATER/MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION:

TABLE 3.3.9-1

1. Reactor Vessel Water Level - High, Level 8 For the Feedwater System, it trips the Reactor AOO Manual Feedwater Pump Trip.

Feedwater Pumps to Prevents Overfilling the RPV and Flooding Main Steam Lines.

For the Main Turbine, it Initiates A Turbine Trip AOO Manual Main Turbine Trip.

and concurrent RPS SCRAM By Closure Of Either The Turbine Stop Valves or Control Valves.

LIMERICK UFSAR

REFERENCES:

UFSAR Feedwater Pump Level 8 Trip UFSAR Event Section Description Section 7.7.1.4 Feedwater Control System 15.1.2 Feedwater Max Demand Controller Failure 15.1.3 Pressure Regulator Fails Open UFSAR Main Turbine Level 8 Trip UFSAR Event Section Description Section 10.2 Turbine Generator 15.1.2 Feedwater Max Demand Controller Failure 15.1.3 Pressure Regulator Fails Open 15.3.1 Both Recirculation Pumps Trip 15.3.2 Recirculation Flow Control Failure- Decreasing Flow

ENCLOSURE 1 License Amendment Request Limerick Generating Station, Units 1 and 2 Docket Nos. 50-352 and 50-353 Response to Request for Additional Information License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b."

List of Revised Required Actions to Corresponding PRA Functions

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.1.5.a Three Standby Liquid Yes Provide a backup One pump and Same SSCs are modeled Only one pump and Control pumps and two capability for bringing the corresponding flow consistent with TS scope corresponding injection paths reactor from full power to a paths and so can be directly explosive valve cold, Xenon-free shutdown evaluated in the RTR operable tool for the RICT Program.

The success criteria in the PRA are consistent with the design basis.

3.3.1.a Four reactor protection Yes Provide reactor trip signal Generally, one-out-of- Same Some inputs such as Number of operable system channels (Note based on plant parameters two twice logic loss of condenser channels for one 3) vacuum are not function in one trip modeled. Conservatively system less than will be treated as loss of minimum channel. (Note 3)

The success criteria in the PRA are consistent with the design basis.

3.3.1.b See LCO Condition 3.3.1.a Number of operable channels in one trip system less than minimum 3.3.1.c See LCO Condition 3.3.1.a Number of operable channels in both trip systems for one or more Functional Units E1-1

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.3.2.b.1 Reactor Pressure Yes Provide reactor isolation One of two channels Same SSCs are modeled Less than minimum Vessel Isolation signal based on plant consistent with TS scope number of channels actuation parameters and so can be directly per trip system for instrumentation evaluated in the RTR one trip system - (Note 4) tool for the RICT tripped condition Program. (Note 4) would cause an The success criteria in isolation the PRA are consistent with the design basis.

3.3.2.b.2.a See LCO Condition Less than minimum 3.3.2.b.1 number of channels per trip system for one trip system -

tripped condition would not cause an isolation (function common to RPS instrumentation) 3.3.2.b.2.b See LCO Condition Less than minimum 3.3.2.b.1 number of channels per trip system for one trip system -

tripped condition would not cause an isolation (function not common to RPS instrumentation)

E1-2

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.3.3.b ECCS actuation Yes Actuation of ECCS One of two channels Same SSCs are modeled One or more instrumentation systems (HPCI, LPCI, consistent with TS scope actuation (Note 6,7) LPCS and ADS) and so can be directly instrumentation evaluated in the RTR channel inoperable/ tool for the RICT Program. (Note 8)

Table 3.3.3-1 The success criteria in the PRA are consistent with the design basis.

3.3.3.c.1 ECCS actuation Yes Actuation of ADS One of two channels Same SSCs are modeled Either ADS trip instrumentation consistent with TS scope system inoperable and so can be directly with HPCI and RCIC evaluated in the RTR operable tool for the RICT Program.

The success criteria in the PRA are consistent with the design basis.

3.3.3.c.2 See LCO Condition Either ADS trip 3.3.3.c.1 system inoperable with HPCI and RCIC inoperable E1-3

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.3.4.1.b. ATWS-RPT system Yes Reduction in core power in One of two channels Same SSCs are modeled Number of operable instrumentation ATWs by reduction in core consistent with TS scope channels one less (Note 8) flow and so can be directly than required evaluated in the RTR tool for the RICT Program. (Note 8)

The success criteria in the PRA are consistent with the design basis.

3.3.4.1.c.1 See LCO Condition Number of operable 3.3.4.1.b channels two less than required- one reactor level, one reactor pressure 3.3.4.1.d See LCO Condition .

One trip system 3.3.4.1.b inoperable 3.3.4.2.b EOC-RPT system Yes Reduction in core power at One of two channels Same SSCs are modeled One less than instrumentation end of core life by consistent with TS scope required number of (Note 5) reduction in core flow after and so can be directly channels per trip reactor trip evaluated in the RTR system tool for the RICT Program (Note 5).

The success criteria in the PRA are consistent with the design basis.

E1-4

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.3.4.2.c.1 See LCO Condition Two less than 3.3.4.2.b required number of channels per trip system - one turbine control valve channel and on turbine stop valve channel 3.3.4.2.d See LCO Condition One trip system 3.3.4.2.b inoperable 3.3.5.b RCIC actuation Yes Actuation of RCIC system One of two channels Same SSCs are modeled Less than required instrumentation consistent with TS scope number of channels and so can be directly operable/ evaluated in the RTR tool for the RICT Table 3.3.5-1 Program.

The success criteria in the PRA are consistent with the design basis.

3.3.9.b High water level trip Yes Shutdown of non-safety One of two channels Same SSCs are modeled One less than instrumentation (FW related turbine driven consistent with TS scope required number of and Main Turbine) equipment prior to and so can be directly channels operable damage from water evaluated in the RTR intrusion into the steam tool for the RICT supply lines Program.

The success criteria in the PRA are consistent with the design basis.

E1-5

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.3.9.c See LCO Condition 3.3.9.b Two less than required number of channels operable 3.4.7.a Main steam isolation Yes Isolation of the main One valve in each line Same SSCs are modeled One or more MSIVs valves steam lines to minimize consistent with TS scope inoperable leakage from the and so can be directly containment. evaluated in the RTR tool for the RICT Program.

The success criteria in the PRA are consistent with the design basis.

3.5.1.a.1 Two subsystems Yes To assure that the core is One of two loops. Same SSCs are modeled One CSS subsystem (loops) of CSS each adequately cooled consistent with TS scope inoperable with at containing two pumps following a loss-of- coolant and so can be directly least two LPCI and an injection path accident. evaluated in the RTR subsystems tool for the RICT operable Program.

The success criteria in the PRA are consistent with the design basis.

E1-6

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.5.1.b.4 Four LPCI Yes To assure that the core is Two of four trains One of four trains SSCs are modeled Two LPCI subsystems (trains) adequately cooled consistent with TS scope subsystems each containing a following a loss-of-coolant and so can be directly inoperable suppression pool accident evaluated in the RTR suction path, pump tool for the RICT and discharge path to Program.

the reactor vessel The success criteria in the PRA are consistent with the design basis for each train. Overall PRA success criteria supported by calculations.

3.5.1.b.5 See LCO Condition Three LPCI 3.4.1.b.4 subsystems inoperable E1-7

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.5.1.c.1 HPCI system Yes Reactor inventory control HPCI train HPCI with flow through Calculations show that HPCI system for small break LOCA. either injection path. the HPCI flow rate inoperable through either the feedwater or core spray injection path is adequate. Injection only through feedwater is procedurally directed by the EOPs for certain events. SSCs are modeled consistent with TS scope and so can be directly evaluated in the RTR tool.

3.5.1.c.2 See LCO Condition HPCI system and 3.5.1.c.1 one CSS or LPCI subsystem inoperable 3.5.1.d.1 ADS (5 SRVs) Yes Rapid reactor vessel Two of five ADS Two of five ADS SRVs SSCs are modeled One required ADS depressurization to allow SRVs consistent with TS scope valve inoperable low pressure ECCS and so can be directly injection. evaluated in the RTR tool for the RICT Program.

E1-8

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.6.1.3.a.1 Primary containment Yes Containment Integrity One of two Same The containment airlock One primary airlock containment air lock is explicitly modeled in containment airlock doors closed. the PRA and so can be door inoperable directly evaluated in the RTR tool for the RICT Program.

The success criteria in the PRA are consistent with the design basis.

3.6.2.2.a Two loops of No Steam condensation and One independent loop Not modeled Suppression pool spray One suppression Suppression pool cooling of Suppression consisting of one is not modeled in the pool spray loop spray mode of RHR Pool air space. operable RHR pump PRA.

inoperable This type of failure will be analyzed as a failure of drywell spray. This is acceptable given the connection via the downcomers of the Drywell and Wetwell airspaces 3.6.2.3.a Two loops Yes Maintain the suppression One loop Same SSCs are modeled One suppression Suppression pool pool temperature to be consistent with TS scope pool cooling loop cooling mode of RHR able to quench a reactor and so can be directly inoperable blowdown and remove evaluated in the RTR heat from Primary tool for the RICT Containment. Program.

The success criteria in the PRA are consistent with the design basis.

E1-9

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.6.2.3.a** footnote See LCO Condition One suppression 3.6.2.3.a pool cooling loop inoperable for RHRSW pipe replacement 3.6.3.a Primary containment Yes Primary containment At least one isolation At least one isolation Not all valves modeled.

One or more PCIV isolation valves, isolation valve operable in valve operable in each If specific valve greater inoperable instrumentation line each penetration penetration. Lines less than two inches is not excess flow check than two inches in modeled, a generic valves diameter are not isolation failure event will considered a significant be used. This is leakage path conservative due to the remaining operable valve in the penetration.

3.6.4.1.a Suppression chamber Yes Drywell wetwell pressure Two of four pairs Same SSCs are modeled One or more to drywell vacuum equalization consistent with TS scope vacuum breakers in breakers and so can be directly one of the three evaluated in the RTR required pairs of tool for the RICT vacuum breakers Program.

inoperable for The success criteria in opening, but known the PRA are consistent to be closed with the design basis.

E1-10

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.7.1.1.a.2 Two subsystems Yes Decay heat removal. One pump and heat Same SSCs are modeled One RHRSW pump (loops) of RHRSW exchanger per unit consistent with TS scope in each subsystem with two common and so can be directly inoperable pumps per loop and evaluated in the RTR unit specific heat tool for the RICT exchangers Program.

The success criteria in the PRA are consistent with the design basis.

3.7.1.1.a.3 See LCO Condition One RHRSW 3.7.1.1.a.2 subsystem inoperable 3.7.1.1.a.3.a See LCO Condition A RHRSW loop 3.7.1.1.a.2 inoperable for piping replacement 3.7.1.1.a.3.b See LCO Condition B RHRSW loop 3.7.1.1.a.2 inoperable for piping replacement 3.7.1.2.a.3 Two independent ESW Yes Supply cooling water to One pump per loop Same SSCs are modeled One emergency loops (A and B), with safety- related consistent with TS scope service water loop two 50% system components, including the and so can be directly inoperable capacity (100% loop diesel generators, RHR evaluated in the RTR capacity) pumps per pumps room coolers and tool for the RICT loop. chillers. Program.

The success criteria in the PRA are consistent with the design basis.

E1-11

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.7.1.2.a.3# footnote See LCO Condition One Emergency 3.7.1.2.a.3 Service Water loop inoperable during RHRSW piping replacement 3.7.3.a RCIC system Yes Reactor inventory control RCIC train Same SSCs are modeled RCIC system whenever the vessel is consistent with TS scope inoperable isolated from the main and so can be directly condenser and feedwater evaluated in the RTR system. tool for the RICT Program.

The success criteria in the PRA are consistent with the design basis.

3.7.8 Requirements 9 main turbine Yes Reactor pressure control Seven of nine turbine Same Modeled as single event of the LCO not met bypass valves bypass valve for less than required or Main Turbine number available.

Bypass System The success criteria in inoperable the PRA are consistent with the design basis criteria.

E1-12

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.8.1.1.b* footnote Four emergency diesel Yes Provide power to safety Three of four diesel As needed to supply SSCs are modeled Two diesel generators per Unit related buses when offsite generators supported functions. consistent with the TS generators power to them is lost. scope and so can be inoperable RHRSW directly evaluated using piping replacement the RTR tool for the RICT Program.

The success criteria in the PRA are consistent with the design basis criteria.

3.8.1.1.d Two physically Yes Provide power to the One of two off site Same Consistent with the TS One offsite circuit independent circuits and onsite Class 1E buses. sources. scope and so can be and one diesel four emergency diesel directly evaluated using generator inoperable generators the RTR tool for the RICT Program.

The success criteria in the PRA are consistent with the design basis criteria.

3.8.1.1.e.1* footnote See LCO Condition For two train 3.8.1.1.b* footnote systems, one or more diesel generators inoperable RHRSW piping replacement E1-13

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.8.1.1.f See LCO Condition One offsite circuit 3.8.1.1.d inoperable 3.8.1.1.g See LCO Condition Two offsite circuits 3.8.1.1.d inoperable 3.8.2.1.a.3 Four DC divisions with Yes Ensure availability of Three of four DC As needed to supply SSCs are modeled Restore chargers battery and charger. required DC power to shut divisions supported functions. consistent with the TS Divisions 1 and 2 have down the reactor and scope and so can be 2 125VDC batteries maintain it in a safe directly evaluated using forming a 250VDC condition the RTR tool for the supply. Divisions 3 and RICT Program.

4 have a single 125 VDC battery. The success criteria in the PRA are consistent with the design basis criteria.

3.8.2.1.c DC power sources See LCO Condition Any battery(ies) on 3.8.2.1.a one division of required DC electrical power sources inoperable E1-14

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Table E1-1: In Scope TS/LCO Conditions to Corresponding PRA Functions Proposed TS SSCs Covered by SSCs Function Covered Design PRA Success Comments LCO TS LCO Condition Modeled by TS LCO Success Criteria Condition in PRA Condition Criteria 3.8.3.1.a Four divisions of AC Yes Provide AC power to Three of four divisions As needed to supply SSCs are modeled One required AC power distribution safety related systems and supported functions. consistent with the TS distribution system systems (including the components scope and so can be divisions not 4kV bus, 480V LC, 480 directly evaluated using energized MCC, 120 V dist. the RTR tool for the panels) (Note 9) RICT Program.

(Note 10)

The success criteria in the PRA are consistent with the design basis criteria.

3.8.3.1.b Four divisions of DC Yes Provide DC power to Three of four divisions As needed to supply SSCs are modeled One required DC power distribution safety related systems and supported functions. consistent with the TS distribution system including the fuse box, components scope and so can be divisions not distribution panel, and directly evaluated using energized in some cases MCC. the RTR tool for the RICT Program.

The success criteria in the PRA are consistent with the design basis criteria.

Notes:

(1) Deleted (2) Deleted (3) The reactor protection system is made up of two independent trip systems (A and B). Each trip system contains 2 channels (A1, A2 and B1, B2). The outputs of the channels in a trip system are combined in a logic so that either channel will trip that trip system. The tripping of both trip systems will produce a reactor scram. Each channel contains the various functional inputs to RPS such Reactor level, MSIV E1-15

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions closure, etc. Loss of any functional input does not prevent the channel from responding to other inputs. Use of a channel inoperable as a surrogate for a non-modeled functional input is conservative as it encompasses loss of all the inputs to the channel rather than any single input to the channel.

(4) Four instrumentation channels are provided to ensure protective action when required and to prevent inadvertent isolation resulting from instrumentation malfunctions. The output trip signal of each instrumentation channel initiates a trip logic. The output trip signals of the trip logics are combined in one-out-of-two-twice configuration for the MSIVs. Failure of any one trip logic does not result in an inadvertent trip.

Trip logics A or C and B or D are required to initiate main steam line isolation action.

Instrumentation channels A and B or C and D are required to initiate isolation of either inboard or outboard valves, respectively. For the remaining systems. Failure of any one channel does not result in inadvertent action (5) For each EOC-RPT system, the sensor relay contacts are arranged to form a 2-out-of-2 logic for the fast closure of turbine control valves and a 2-out-of-2 logic for the turbine stop valves. The operation of either logic will actuate the EOC-RPT system and trip both recirculation pumps.

(6) Individual pieces of instrumentation such as a pressure transmitter may be shared by multiple design basis functions (7) The control logic for ECCS actuation, for each unit, is split into four electrical divisions (Division I, II, III, and IV). Reactor low water level (Level 1) is sensed by eight trip units in the Reactor Instrumentation System (two per Division). The trip unit outputs are connected in a one-out-of-two taken twice mixed logic to provide an automatic initiation signal Drywell high pressure signals are sent from the Reactor Instrumentation System (RIS) to eight high drywell pressure relay contacts (two per Division). Reactor low pressure is sensed by twelve trip units in the Reactor Instrumentation System (four in Division I, four in II, two in Division III, and two in Division IV). The trip unit output relay signals are in series with the high drywell pressure signal and each such set is connected as a portion of the combined drywell high pressure and reactor low pressure initiation circuit.

The high drywell pressure relay contacts and low reactor pressure relay contacts are connected in series to provide an automatic ECCS System initiation signal.

For HPCI the low reactor water level is sensed by four trip units in the Reactor Instrumentation System. The four trip units are connected in a one-out-of-two taken twice logic to provide an automatic initiation signal.

For RCIC the low reactor water level is sensed by four trip units in the RIS. The four trip units are connected in a one-out-of-two taken twice logic to provide an automatic initiation signal.

(8) ATWS-RPT system instrumentation is part of the redundant reactivity control system and has 2 divisions each composed of two channels into which the functional inputs are fed. Both channels within a division must trip to initiate the automatic function of tripping both recirculation pumps. This is a 2-out-of-2 taken once logic. Either division can accomplish the function independently.

(9) The electrical loading of the 4KV 1E buses at Limerick Generating Station is asymmetric primarily for the loading of the common cooling water systems and HVAC systems. These systems are the Emergency Service Water (ESW) system, the Residual Heat Removal Service Water (RHRSW) system, the standby gas treatment system (SGTS) and the control room emergency fresh air system (CREFAS). The CRD and Instrument air system for each unit are also powered by 2 of the 4 divisions as they are two train systems. There are four 4KV 1E buses per unit, D11, D12, D13 and D14 on Unit 1, and D21, D22, D23 and D24 on Unit 2. SGTS trains are powered by buses D11 and D12 and CREFAS by D13 and D14. ESW is powered by Unit 1 buses D11 and D12 and Unit 2 buses D23 and D24. RHRSW is powered by Unit 1 buses D11 and D12 and Unit 2 buses D21 and D22. See table below.

E1-16

Response to Request for Additional Information Enclosure 1 LAR to Adopt TSTF-505, Rev. 2 Docket Nos. 50-352 and 50-353 List of Revised Required Actions to Corresponding PRA Functions Unit Unit 1 Unit 2 Safeguard D11 D12 D13 D14 D21 D22 D23 D24 bus System/train 0A ESW 0B ESW Alt. 0C ESW Alt. 0D ESW 0C ESW 0D ESW 0A RHRSW 0B RHRSW 0C RHRSW 0D RHRSW 0A SGTS 0B SGTS 0A CREFAS 0B CREFAS 1A RERS 1B RERS 2A RERS 2B RERS 1A CRD 1B CRD 2A CRD 2B CRD E1-17