Text

Issuance of Amendment Nos. 271 and 273 Regarding Technical Specifications to Adopt TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b
	ML23103A133
Person / Time
Site:	Point Beach
Issue date:	06/01/2023
From:	Scott Wall; Plant Licensing Branch III
To:	Coffey B; Point Beach
	Wall, S P
References
	EPID L-2022-LLA-0074
	Download: ML23103A133 (124)
	v • d • e

June 1, 2023 Mr. Bob Coffey Executive Vice President, Nuclear Division and Chief Nuclear Officer Florida Power & Light Company Mail Stop: EX/JB 700 Universe Blvd Juno Beach, FL 33408

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT NOS. 271 AND 273 REGARDING TECHNICAL SPECIFICATIONS TO ADOPT TSTF-505, REVISION 2, PROVIDE RISK-INFORMED EXTENDED COMPLETION TIMES - RITSTF INITIATIVE 4b (EPID L-2022-LLA-0074)

Dear Mr. Coffey:

The U.S. Nuclear Regulatory Commission (NRC) has issued the enclosed Amendment Nos. 271 and 273 to Renewed Facility Operating License Nos. DPR-24 and DPR-27, respectively, for the Point Beach Nuclear Plant, Units 1 and 2 (Point Beach). The amendment consists of changes to the technical specifications (TSs) in response to your application dated May 20, 2022, as supplemented by letters dated July 11, 2022, January 11, 2023, and February 21, 2023.

The amendment revises the TS requirements to permit the use of risk-informed completion times for actions to be taken when limiting conditions for operation are not met.

The changes are based on Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF [Risk-Informed TSTF] Initiative 4b, dated July 2, 2018. The NRC issued a final model safety evaluation approving TSTF-505, Revision 2 on November 21, 2018.

B. Coffey A copy of our related safety evaluation is also enclosed. The Notice of Issuance will be included in the Commissions monthly Federal Register notice.

Sincerely,

/RA/

Scott P. Wall, Senior Project Manager Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-266 and 50-301

Enclosures:

1. Amendment No. 271 to DPR-24

2. Amendment No. 273 to DPR-27

3. Safety Evaluation cc: Listserv

NEXTERA ENERGY POINT BEACH, LLC DOCKET NO. 50-266 POINT BEACH NUCLEAR PLANT, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 271 License No. DPR-24

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

A. The application for amendment by NextEra Energy Point Beach, LLC (the licensee), dated May 20, 2022, as supplemented by letters dated July 11, 2022, January 11, 2023, and February 21, 2023, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

Enclosure 1

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 4.B of the Renewed Facility Operating License No. DPR-24 is hereby amended to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 271, are hereby incorporated in the renewed operating license. NextEra Energy Point Beach shall operate the facility in accordance with the Technical Specifications.

3. This license amendment is effective as of its date of issuance and shall be implemented within 180 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Digitally signed by Venkataiah Sreenivas Date: 2023.06.01 11:06:50 -04'00' V. Sreenivas, Acting Chief Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Renewed Facility Operating License Date of Issuance: June 1, 2023

NEXTERA ENERGY POINT BEACH, LLC DOCKET NO. 50-301 POINT BEACH NUCLEAR PLANT, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 273 License No. DPR-27

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

A. The application for amendment by NextEra Energy Point Beach, LLC (the licensee), dated May 20, 2022, as supplemented by letters dated July 11, 2022, January 11, 2023, and February 21, 2023, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

Enclosure 2

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 4.B of the Renewed Facility Operating License No. DPR-27 is hereby amended to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 273, are hereby incorporated in the renewed operating license. NextEra Energy Point Beach shall operate the facility in accordance with Technical Specifications.

3. This license amendment is effective as of its date of issuance and shall be implemented within 180 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Digitally signed by Venkataiah Sreenivas Date: 2023.06.01 11:05:17 -04'00' V. Sreenivas, Acting Chief Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Renewed Facility Operating License Date of Issuance: June 1, 2023

ATTACHMENT TO LICENSE AMENDMENT NO. 271 AND 273 TO RENEWED FACILITY OPERATING LICENSE NOS. DPR-24 AND DPR-27 DOCKET NOS. 50-266 AND 50-301 Replace the following pages of Renewed Facility Operating License Nos. DPR-24 and DPR-27, and Appendix A, Technical Specifications, with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Renewed Facility Operating License No. DPR-24 REMOVE INSERT Renewed Facility Operating License No. DPR-27 REMOVE INSERT Appendix A, Technical Specifications REMOVE INSERT 1.3-13 1.3-13

-- 1.3-14 3.3.1-1 through 3.3.1-20 3.3.1-1 through 3.3.1-22 3.3.2-1 through 3.3.2-9 3.3.2-1 through 3.3.2-10 3.4.11-1 through 3.4.11-3 3.4.11-1 through 3.4.11-4 3.5.2-1 through 3.5.2-2 3.5.2-1 through 3.5.2-3 3.6.2-4 through 3.6.2-5 3.6.2-4 through 3.6.2-5 3.6.3-1 through 3.6.3-3 3.6.3-1 through 3.6.3-3 3.7.2-1 through 3.7.2-2 3.7.2-1 through 3.7.2-3 3.7.4-1 3.7.4-1 3.7.5-1 through 3.7.5-2 3.7.5-1 through 3.7.5-2 3.7.7-1 through 3.7.7-2 3.7.7-1 through 3.7.7-2 3.7.8-1 through 3.7.8-4 3.7.8-1 through 3.7.8-5 3.8.1-2 through 3.8.1-8 3.8.1-2 through 3.8.1-10 3.8.4-1 through 3.8.4-2 3.8.4-1 through 3.8.4-2 3.8.7-1 3.8.7-1 5.5-6 through 5.5-19 5.5-6 through 5.5-20

D. Pursuant to the Act and 10 CFR Parts 30, 40 and 70, NextEra Energy Point Beach to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and E. Pursuant to the Act and 10 CFR Parts 30 and 70, NextEra Energy Point Beach to possess such byproduct and special nuclear materials as may be produced by the operation of the facility, but not to separate such materials retained within the fuel cladding.

4. This renewed operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations: 10 CFR Part 20, Section 30.34 of 10 CFR Part 30, Section 40.41 of 10 CFR Part 40, Sections 50.54 and 50.59 of 10 CFR Part 50, and Section 70.32 of 10 CFR Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified below:

A. Maximum Power Levels NextEra Energy Point Beach is authorized to operate the facility at reactor core power levels not in excess of 1800 megawatts thermal.

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 271, are hereby incorporated in the renewed operating license.

NextEra Energy Point Beach shall operate the facility in accordance with Technical Specifications.

C. Spent Fuel Pool Modification The licensee is authorized to modify the spent fuel storage pool to increase its storage capacity from 351 to 1502 assemblies as described in licensees application dated March 21, 1978, as supplemented and amended. In the event that the on-site verification check for poison material in the poison assemblies discloses any missing boron plates, the NRC shall be notified and an on-site test on every poison assembly shall be performed.

Renewed License No. DPR-24 Amendment No. 271

C. Pursuant to the Act and 10 CFR Parts 30, 40 and 70, NextEra Energy Point Beach to receive, possess and use at any time any byproduct, source, and special nuclear material as sealed neutron sources for reactor startup, sealed source for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; D. Pursuant to the Act and 10 CFR Parts 30, 40 and 70, NextEra Energy Point Beach to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and E. Pursuant to the Act and 10 CFR Parts 30 and 70, NextEra Energy Point Beach to possess such byproduct and special nuclear materials as may be produced by the operation of the facility, but not to separate such materials retained within the fuel cladding.

4. This renewed operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations: 10 CFR Part 20, Section 30.34 of 10 CFR Part 30, Section 40.41 of 10 CFR Part 40, Sections 50.54 and 50.59 of 10 CFR Part 50, and Section 70.32 of 10 CFR Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified below:

A. Maximum Power Levels NextEra Energy Point Beach is authorized to operate the facility at reactor core power levels not in excess of 1800 megawatts thermal.

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 273, are hereby incorporated in the renewed operating license.

NextEra Energy Point Beach shall operate the facility in accordance with Technical Specifications.

C. Spent Fuel Pool Modification The licensee is authorized to modify the spent fuel storage pool to increase its storage capacity from 351 to 1502 assemblies as described in licensees application dated March 21, 1978, as supplemented and amended. In the event that the on-site verification check for poison material in the poison assemblies discloses any missing boron plates, the NRC shall be notified and an on-site test on every poison assembly shall be performed.

Renewed License No. DPR-27 Amendment No. 273

Completion Times 1.3 1.3 Completion Times EXAMPLES (continued)

EXAMPLE 1.3-8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One A.1 Restore 7 days subsystem subsystem to inoperable. OPERABLE OR status.

In accordance with the Risk Informed Completion Time Program B. Required B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Action and associated AND Completion Time not met. B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months When a subsystem is declared inoperable, Condition A is entered.

The 7 day Completion Time may be applied as discussed in Example 1.3-2. However, the licensee may elect to apply the Risk Informed Completion Time Program which permits calculation of a Risk Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day Completion Time.

The RICT cannot exceed 30 days. After the 7 day Completion Time has expired, the subsystem must be restored to OPERABLE status within the RICT or Condition B must also be entered.

The Risk Informed Completion Time Program requires recalculation of the RICT to reflect changing plant conditions. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

Point Beach 1.3-13 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Completion Times 1.3 1.3 Completion Times If the 7 day Completion Time clock of Condition A has expired and subsequent changes in plant condition result in exiting the applicability of the Risk Informed Completion Time Program without restoring the inoperable subsystem to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start.

If the RICT expires or is recalculated to be less than the elapsed time since the Condition was entered and the inoperable subsystem has not been restored to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable subsystems are restored to OPERABLE status after Condition B is entered, Condition A is exited, and therefore, the Required Actions of Condition B may be terminated.

IMMEDIATE When "Immediately" is used as a Completion Time, the COMPLETION TIME Required Action should be pursued without delay and in a controlled manner.

Point Beach 1.3-14 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 3.3 INSTRUMENTATION 3.3.1 Reactor Protection System (RPS) Instrumentation LCO 3.3.1 The RPS instrumentation for each Function in Table 3.3.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.1-1.

ACTIONS

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

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions A.1 Enter the Condition Immediately with one or more referenced in Table required channels or 3.3.1-1 for the trains inoperable. channel(s) or train(s).

B. One Manual Reactor Trip B.1 Restore channel to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months channel inoperable. OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program C. One Manual Reactor Trip C.1 Restore channel to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months channel inoperable. OPERABLE status.

OR C.2 Open reactor trip 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months breakers (RTBs).

(continued)

Point Beach 3.3.1-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One channel inoperable. D.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OR In accordance with the Risk Informed Completion Time Program E. One channel inoperable. E.1 Place channel in trip. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR In accordance with the Risk Informed Completion Time Program F. One Intermediate Range F.1 Reduce THERMAL 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Neutron Flux channel POWER to < P-6.

inoperable.

OR F.2 Increase THERMAL 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months POWER to > P-10.

(continued)

Point Beach 3.3.1-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME G. Two Intermediate Range G.1 Suspend operations Immediately Neutron Flux channels involving positive inoperable. reactivity additions.

AND G.2 Reduce THERMAL 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months POWER to < P-6.

H. One Source Range H.1 Suspend operations Immediately Neutron Flux channel involving positive inoperable. reactivity additions.

I. Two Source Range I.1 Open RTBs. Immediately Neutron Flux channels inoperable.

J. One Source Range J.1 Restore channel to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Neutron Flux channel OPERABLE status.

inoperable.

OR J.2 Open RTBs. 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months (continued)

Point Beach 3.3.1-3 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME K. One channel inoperable. K.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OR In accordance with the Risk Informed Completion Time Program L. One Reactor Coolant L.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Flow-Low (Single Loop) channel inoperable. OR In accordance with the Risk Informed Completion Time Program M. One Reactor Coolant M.1 Restore channel to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Pump Breaker Position OPERABLE status.

(Single Loop) channel OR inoperable.

In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.3.1-4 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME N. One inoperable channel. N.1 Restore channel to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program O. One turbine trip channel O.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable.

OR In accordance with the Risk Informed Completion Time Program P. One train inoperable. -----------------NOTE-----------------

One train may be bypassed for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for surveillance testing provided the other train is OPERABLE.

P.1 Restore train to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.3.1-5 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME Q. One RTB inoperable. -----------------NOTE-----------------

One RTB may be bypassed for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months provided the other RTB is OPERABLE.

Q.1 Restore RTB to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program R. One or more channel(s) R.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. required state for existing unit conditions.

OR R.2 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months S. One or more channel(s) S.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. required state for existing unit conditions.

OR S.2 Be in MODE 2. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months T. One RTB or trip T.1 Restore RTB or RTB 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months mechanism for one RTB trip mechanism to inoperable. OPERABLE status.

OR T.2 Open RTBs. 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months (continued)

Point Beach 3.3.1-6 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME U. One trip mechanism U.1 Restore trip mechanism 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable for one RTB. to OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program V. One reactor trip bypass V.1 Restore RTBB or RTBB 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months breaker (RTBB) or trip trip mechanism to mechanism for one OPERABLE status.

RTBB inoperable.

OR V.2 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months W. One reactor trip bypass W.1 Restore RTBB or RTBB 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months breaker (RTBB) or trip trip mechanism to mechanism for one OPERABLE status.

RTBB inoperable.

OR W.2 Open RTBs and 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months RTBBs.

X. One train inoperable. X.1 Restore train to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OPERABLE status.

OR X.2 Open RTBs. 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months (continued)

Point Beach 3.3.1-7 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME Y. Required Action and Y.1 Be in Mode 3 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition B, D, P, Q, or U not met.

Z. Required Action and Z.1 Reduce THERMAL 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion POWER to < P-7.

Time of Condition E, K or N not met.

AA. Required Action and AA.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion POWER to < P-8.

Time of Condition L or M not met.

BB. Required Action and BB.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion POWER to < P-9.

Time of Condition O not met.

Point Beach 3.3.1-8 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.1-1 to determine which SRs apply for each RPS Function.

SURVEILLANCE FREQUENCY SR 3.3.1.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.1.2 ---------------------------NOTES-------------------------

1. Adjust NIS channel if absolute difference is > 2%.

2. Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is 15%

RTP.

In accordance Compare results of calorimetric heat balance with the calculation to Nuclear Instrumentation System Surveillance (NIS) channel output. Frequency Control Program SR 3.3.1.3 ---------------------------NOTES-------------------------

1. Adjust NIS channel if absolute difference is 3%.

2. Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is 50%

RTP.

In accordance Compare results of the incore detector with the measurements to NIS AFD. Surveillance Frequency Control Program (continued)

Point Beach 3.3.1-9 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.4 ----------------------------NOTE--------------------------

This Surveillance must be performed on the reactor trip bypass breaker prior to placing the bypass breaker in service.

In accordance Perform TADOT. with the Surveillance Frequency Control Program SR 3.3.1.5 ---------------------------NOTES-------------------------

1. Not required to be performed for the Source Range Neutron Flux Trip Function until 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after power is below P-6.

2. Not required to be performed for the RCP Breaker Position (Two Loops), Reactor Coolant Flow Low (Two Loops) and Underfrequency Bus A01 and A02 Trip Functions and the P-6, P-7, P-8, P-9 and P-10 Interlocks.

In accordance Perform ACTUATION LOGIC TEST. with the Surveillance Frequency Control Program SR 3.3.1.6 ----------------------------NOTE--------------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is 50% RTP.

In accordance Calibrate excore channels to agree with incore with the detector measurements. Surveillance Frequency Control Program (continued)

Point Beach 3.3.1-10 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.7 ----------------------------NOTE--------------------------

Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after entry into MODE 3.

In accordance Perform COT. with the Surveillance Frequency Control Program (continued)

Point Beach 3.3.1-11 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.8 ----------------------------NOTE-------------------------

This Surveillance shall include verification that interlocks P-6 and P-10 are in their required state for existing unit conditions.

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

-- Only required when not performed Perform COT. within the frequency specified in the Surveillance Frequency Control Program Prior to reactor startup AND Four hours after reducing power below P-10 for power and intermediate range instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND In accordance with the Surveillance Frequency Control Program (continued)

Point Beach 3.3.1-12 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.9 Perform TADOT. In accordance with the Surveillance Frequency Control Program SR 3.3.1.10 ----------------------------NOTE--------------------------

This Surveillance shall include verification that the time delays are adjusted to the prescribed values.

In accordance with the Perform CHANNEL CALIBRATION. Surveillance Frequency Control Program SR 3.3.1.11 ----------------------------NOTE--------------------------

Neutron detectors are excluded from CHANNEL CALIBRATION.

In accordance with the Perform CHANNEL CALIBRATION. Surveillance Frequency Control Program SR 3.3.1.12 Perform COT. In accordance with the Surveillance Frequency Control Program SR 3.3.1.13 Perform TADOT. In accordance with the Surveillance Frequency Control Program (continued)

Point Beach 3.3.1-13 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.14 Perform TADOT. Prior to exceeding the P-9 interlock whenever the unit has been in MODE 3, if not performed within previous 31 days.

SR 3.3.1.15 ---------------------------NOTE---------------------------

This Surveillance must be performed on the RCP Breaker Position (Two Loop),

Reactor Coolant Flow - Low (Two Loop) and Underfrequency Bus A01 and A02 Trip Functions and the P-6 , P-7, P-8, P-9 and P-10 Interlocks.

In accordance Perform ACTUATION LOGIC TEST. with the Surveillance Frequency Control Program Point Beach 3.3.1-14 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 Table 3.3.1-1 (page 1 of 8)

Reactor Protection System Instrumentation FUNCTION APPLICABLE REQUIRED SURVEILLANCE ALLOWABLE NOMINAL TRIP MODES CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

1. Manual 1,2 2 B SR 3.3.1.13 NA NA Reactor Trip 3 (a) , 4 (a) , 5 (a) 2 C SR 3.3.1.13 NA NA

2. Power Range Neutron Flux

a. High 1,2 4 D SR 3.3.1.1 108% RTP 106% RTP SR 3.3.1.2 SR 3.3.1.7 ( m)

SR 3.3.1.11 ( m)

b. Low 1 (b) ,2 4 D SR 3.3.1.1 27% RTP 20% RTP SR 3.3.1.8 ( m)

SR 3.3.1.11 ( m)

3. Intermediate 1 (b) , 2 (c) 2 F,G SR 3.3.1.1 43% RTP 25% RTP Range Neutron SR 3.3.1.8 ( m)

Flux SR 3.3.1.11 ( m)

4. Source Range 2(d) 2 H,I SR 3.3.1.1 < 3.0 E5 cps 1.5 E5 cps Neutron Flux SR 3.3.1.8( m)

SR 3.3.1.11( m) 3(a), 4(a), 5(a) 2 I,J SR 3.3.1.1 < 3.0 E5 cps 1.5 E5 cps SR 3.3.1.7( m)

SR 3.3.1.11( m)

5. Overtemperature 1,2 4 D SR 3.3.1.1 Refer to Note 1 Refer to Note 1 T SR 3.3.1.3 (Page 3.3.1-18) (Page 3.3.1-18)

SR 3.3.1.6 SR 3.3.1.7( m)

SR 3.3.1.11( m)

6. Overpower T 1,2 4 D SR 3.3.1.1 Refer to Note 2 Refer to Note 2 SR 3.3.1.7( m) (Page 3.3.1-19) (Page 3.3.1-19)

SR 3.3.1.11( m)

(continued)

(a) With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.

(b) Below the P-10 (Power Range Neutron Flux) interlock.

(c) Above the P-6 (Intermediate Range Neutron Flux) interlock.

(d) Below the P-6 (Intermediate Range Neutron Flux) interlock.

(m) Table 3.3.1-1 Notes 3 and 4 are applicable Point Beach 3.3.1-15 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 Table 3.3.1-1 (page 2 of 8)

Reactor Protection System Instrumentation APPLICABLE REQUIRED SURVEILLANCE ALLOWABLE NOMINAL TRIP FUNCTION MODES CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

7. Pressurizer Pressure

a. Low 1(e) 4 K SR 3.3.1.1 > 1860 psig 1925 psig SR 3.3.1.7( m)

SR 3.3.1.11( m)

b. High 1,2 3 D SR 3.3.1.1 < 2380 psig 2365 psig SR 3.3.1.7( m)

SR 3.3.1.11( m)

8. Pressurizer 1(e) 3 K SR 3.3.1.1 85% 80%

Water Level SR 3.3.1.7(m)

High SR 3.3.1.11(m)

9. Reactor Coolant Flow-Low

a. Single Loop 1(f) 3 per loop L SR 3.3.1.1 91% 93%

SR 3.3.1.7(m)

SR 3.3.1.11(m)

b. Two Loops 1(g) 3 per loop K SR 3.3.1.1 91% 93%

SR 3.3.1.7(m)

SR 3.3.1.11(m)

10. Reactor Coolant Pump (RCP)

Breaker Position

a. Single Loop 1(f) 1 per RCP M SR 3.3.1.13 NA NA

b. Two Loops 1(g) 1 per RCP N SR 3.3.1.13 NA NA

11. Undervoltage 1(e) 2 per bus K SR 3.3.1.9 3120 V 3170 V Bus A01 & A02 SR 3.3.1.10(m)

(continued)

(e) Above the P-7 (Low Power Reactor Trips Block) interlock.

(f) Above the P-8 (Power Range Neutron Flux) interlock.

(g) Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock.

(m) Table 3.3.1-1 Notes 3 and 4 are applicable Point Beach 3.3.1-16 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 8)

Reactor Protection System Instrumentation APPLICABLE REQUIRED SURVEILLANCE ALLOWABLE NOMINAL TRIP FUNCTION MODES CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

12. Underfrequency 1(e) 2 per bus E SR 3.3.1.10(m) 55.0 Hz 57 Hz Bus A01 & A02

13. Steam Generator 1,2 3 per SG D SR 3.3.1.1 29.5% 31%

(SG) SR 3.3.1.7( m)

Water Level SR 3.3.1.11( m)

Low Low

14. SG Water 1,2 2 per SG D SR 3.3.1.1 > 11% 31%

Level Low SR 3.3.1.7( m)

SR 3.3.1.11( m)

Coincident with 1,2 2 per SG D SR 3.3.1.1 1 E6 lbm/hr 0.8 E6 lbm/hr Steam SR 3.3.1.7( m)

Flow/Feedwater SR 3.3.1.11( m)

Flow Mismatch

15. Turbine Trip

a. Low 1(j) 3 O SR 3.3.1.14 NA NA Autostop Oil Pressure

b. Turbine 2 O SR 3.3.1.14 NA NA 1(j)

Stop Valve Closure

16. Safety Injection 1,2 2 trains P SR 3.3.1.13 NA NA (SI) Input from Engineered Safety Feature Actuation System (ESFAS)

(continued)

(e) Above the P-7 (Low Power Reactor Trips Block) interlock.

(j) Above the P-9 (Power Range Neutron Flux) interlock.

(m) Table 3.3.1-1 Notes 3 and 4 are applicable Point Beach 3.3.1-17 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 8)

Reactor Protection System Instrumentation APPLICABLE REQUIRED CONDITIONS SURVEILLANCE ALLOWABLE NOMINAL TRIP FUNCTION MODES CHANNELS REQUIREMENTS VALUE SETPOINT

17. Reactor Trip System Interlocks

a. Intermediate 2(d) 2 R SR 3.3.1.11 > 4E-11 amp 1E-10 amp Range Neutron SR 3.3.1.12 Flux, P-6

b. Low Power Reactor Trips Block, P-7 (1) Power 1 4 S SR 3.3.1.11 < 13% RTP 10% RTP Range SR 3.3.1.12 Neutron Flux (2) Turbine First 1 2 S SR 3.3.1.11 < 12.8% 10% turbine power Stage SR 3.3.1.12 turbine power Pressure

c. Power Range 1 4 S SR 3.3.1.11 < 38% RTP 35% RTP Neutron Flux, P-8 SR 3.3.1.12

d. Power Range 1(k) 4 S SR 3.3.1.11 (h) (i)

Neutron Flux, P-9 SR 3.3.1.12

e. Power Range 1,2 4 R SR 3.3.1.11 > 6% RTP and 9% RTP Neutron Flux, P-10 SR 3.3.1.12 < 12% RTP

18. Reactor Trip 1,2 2 trains Q SR 3.3.1.4 NA NA Breakers (RTBs) 3(a), 4(a), 5(a) 2 trains T SR 3.3.1.4 NA NA

19. Reactor Trip Breaker 1,2 1 each per U SR 3.3.1.4 NA NA Undervoltage and Shunt RTB Trip Mechanisms 3(a), 4(a), 5(a) 1 each per T SR 3.3.1.4 NA NA RTB (continued)

(a) With the RTBs closed and the Rod Control System capable of rod withdrawal.

(d) Below the P-6 (Intermediate Range Neutron Flux) interlock.

(h) < 38% RTP for full design power Tavg < 572°F or < 53% RTP for full design power Tavg > 572°F. For EOC coastdown, P-9 is not reset if Tavg decreases to < 572°F.

(i) 35% RTP for full design power Tavg < 572°F or 50% RTP for full design power Tavg > 572°F. For EOC coastdown, P-9 is not reset if Tavg decreases to < 572°F.

(k) With 1 of 2 circulating water pump breakers closed and condenser vacuum 22 Hg.

Point Beach 3.3.1-18 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 Table 3.3.1-1 (page 5 of 8)

Reactor Protection System Instrumentation APPLICABLE REQUIRED SURVEILLANCE ALLOWABLE NOMINAL TRIP FUNCTION MODES CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

20. Reactor Trip Bypass 1(l), 2(l) 1 V SR 3.3.1.4 NA NA Breaker and associated Undervoltage Trip 3(l), 4(l), 5(l) 1 W SR 3.3.1.4 NA NA Mechanism

21. Automatic Trip Logic 1, 2, 2 trains P SR 3.3.1.5 NA NA SR 3.3.1.15 3(a), 4(a), 5(a) 2 trains X SR 3.3.1.5 NA NA (a) With RTBs closed and Rod Control System capable of rod withdrawal.

(l) When Reactor Trip Bypass Breakers are racked in and closed and the Rod Control System is capable of rod withdrawal.

Point Beach 3.3.1-19 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 Table 3.3.1-1 (page 6 of 8)

Reactor Protection System Instrumentation Note 1: Overtemperature T 1 1 1 + 1S T( ) To (K1 - K 2 (T( ) - T )( ) + K3 (P - P ) - f( I))

1+ 3S 1+ 4S 1+ 2S Where:

To = indicated T at RTP, F T = average temperature, F T' [*] F P = pressurizer pressure, psig P' = [*] psig K1 < [*]

K2 = [*]

K3 = [*]

1 = [*] sec 2 = [*] sec 3 = [*] sec 4 = [*] sec f( I) = [*] {[*] - (qt - qb)} when (qt - qb) < [*]% RTP 0% of RTP when [*]% RTP < (qt - qb) < [*]% RTP

[*] {(qt - qb) - [*]} when (qt - qb) > [*]% RTP Where qt and qb are percent RTP in the upper and lower halves of the core, respectively, and (qt + qb) is the total THERMAL POWER in percent RTP.

The values denoted with [*] are specified in the COLR.

Point Beach 3.3.1-20 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 Table 3.3.1-1 (page 7 of 8)

Reactor Protection System Instrumentation Note 2: Overpower T 1 5S 1 1 T( ) To [ K4 - K5 ( )( )T - K6 [T( ) - T ))

1 + 3S 5S +1 1+ 4 S 1 + 4S Where:

To = indicated T at RTP, F T = average temperature, F T' [*] F K4 [*]

K5 = [*] for increasing T

= [*] for decreasing T K6 = [*] for T T'

= [*] for T < T' 5 = [*] sec 3 = [*] sec 4 = [*] sec

The values denoted with [*] are specified in the COLR.

Point Beach 3.3.1-21 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

RPS Instrumentation 3.3.1 Table 3.3.1-1 (page 8 of 8)

Reactor Protection System Instrumentation Note 3:

If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

Note 4:

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in FSAR Section 7.2.

Point Beach 3.3.1-22 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 3.3 INSTRUMENTATION 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation LCO 3.3.2 The ESFAS instrumentation for each Function in Table 3.3.2-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.2-1.

ACTIONS

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

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions A.1 Enter the Condition Immediately with one or more required referenced in channels or trains Table 3.3.2-1 for the inoperable. channel(s) or train(s).

B. One channel inoperable. B.1 Restore channel to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.3.2-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One train inoperable. C.1 Restore train to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OPERABLE status.

OR

NOTE--------

Not applicable to Function 2b, Containment Spray Automatic Actuation Logic and Actuation Relays, of Table 3.3-2.

In accordance with the Risk Informed Completion Time Program D. One channel inoperable. D.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OR

NOTE--------

Not applicable to Function 2c, Containment Spray Containment Pressure High-High, of Table 3.3-2.

In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.3.2-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. One or both channel(s) E.1 Restore channel(s) to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. OPERABLE status.

OR E.2.1 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months AND E.2.2 Be in MODE 5. 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months F. One channel inoperable. F.1 Restore channel to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program G. One train inoperable. G.1 Restore train to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program H. One channel inoperable. H.1 Place channel in trip. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.3.2-3 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME I. One or more channels I.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. required state for existing unit condition.

OR I.2.1 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months AND I.2.2 Be in MODE 4. 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months

NOTE----------------- J.1 Restore channel to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Separate Condition entry is OPERABLE status.

allowed for each AFW pump.

OR J. One channel inoperable. J.2 Declare associated AFW pump inoperable.

K. Required Action and K.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition H not met.

L. Required Action and L.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition B or C AND not met.

L.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months M. Required Action and M.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition D, F or AND G not met.

M.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Point Beach 3.3.2-4 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.2.2 ---------------------------NOTE--------------------------

The continuity check may be excluded.

In accordance with the Surveillance Perform ACTUATION LOGIC TEST. Frequency Control Program SR 3.3.2.3 Perform COT. In accordance with the Surveillance Frequency Control Program SR 3.3.2.4 Perform MASTER RELAY TEST. In accordance with the Surveillance Frequency Control Program (continued)

Point Beach 3.3.2-5 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY In accordance with SR 3.3.2.5 Perform SLAVE RELAY TEST. the Surveillance Frequency Control Program SR 3.3.2.6 Perform TADOT. In accordance with the Surveillance Frequency Control Program SR 3.3.2.7 Perform TADOT. In accordance with the Surveillance Frequency Control Program SR 3.3.2.8 ---------------------------NOTE--------------------------

This Surveillance shall include verification that the time constants are adjusted to the prescribed values.

In accordance with Perform CHANNEL CALIBRATION. the Surveillance Frequency Control Program Point Beach 3.3.2-6 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 4)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE REQUIRED SURVEILLANCE ALLOWABLE NOMINAL TRIP FUNCTION MODES CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

1. Safety Injection

a. Manual Initiation 1,2,3,4 2 B SR 3.3.2.7 NA NA

b. Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.5 Relays

c. Containment 1,2,3 3 D SR 3.3.2.1 5.1 psig 4.8 psig PressureHigh SR 3.3.2.3(f)

SR 3.3.2.8(f)

d. Pressurizer 1,2,3(a) 3 D SR 3.3.2.1 1730 psig 1735 psig PressureLow SR 3.3.2.3(f)

SR 3.3.2.8(f)

e. Steam Line 1,2,3(b) 3 per D SR 3.3.2.1 535(c) psig 545 psig PressureLow steam line SR 3.3.2.3(f)

SR 3.3.2.8(f)

2. Containment Spray

a. Manual Initiation 1,2,3,4 2 E SR 3.3.2.7 NA NA

b. Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.5 Relays

c. Containment 1,2,3 2 sets D SR 3.3.2.1 28 psig 25 psig PressureHigh of 3 SR 3.3.2.3(f)

High SR 3.3.2.8(f)

(continued)

(a) Pressurizer Pressure > 2000 psig.

(b) Pressurizer Pressure > 2000 psig, except during Reactor Coolant System hydrostatic testing.

(c) Time constants used in the lead/lag controller are t1 18 seconds and t2 2 seconds.

(f) Table 3.3.2-1 Notes 1 and 2 are applicable.

Point Beach 3.3.2-7 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 2 of 4)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE REQUIRED SURVEILLANCE ALLOWABLE NOMINAL TRIP FUNCTION MODES CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

3. Containment Isolation

a. Manual Initiation 1,2,3,4 2 B SR 3.3.2.7 NA NA

b. Automatic 1,2,3,4 2 trains C SR 3.3.2.4 NA NA Actuation Logic SR 3.3.2.5 and Actuation Relays

c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements, except Manual SI initiation.

4. Steam Line Isolation

a. Manual Initiation 1,2(d),3(d) 1/loop F SR 3.3.2.7 NA NA

b. Automatic 1,2(d),3(d) 2 trains G SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.5 and Actuation Relays

c. Containment 1,2(d),3(d) 3 D SR 3.3.2.1 18 psig 15 psig PressureHigh SR 3.3.2.3(f)

High SR 3.3.2.8(f)

d. High Steam Flow 1,2(d),3(d) 2 per D SR 3.3.2.1 p p corresponding steam line SR 3.3.2.3(f) corresponding to 0.52 x 106 lb/hr SR 3.3.2.8(f) to 0.8 x 106 at 1005 psig lb/hr at 1005 psig Coincident with Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Safety Injection and Coincident with 1,2(d),3(d) 3 D SR 3.3.2.1 > 542 F 543 F TavgLow SR 3.3.2.3(f)

SR 3.3.2.8(f)

e. High High Steam 1,2(d),3(d) 2 per D SR 3.3.2.1 p p corresponding Flow steam line SR 3.3.2.3(f) corresponding to 4.85 x 106 lb/hr SR 3.3.2.8(f) to 4.9 x 106 at 586 psig lb/hr at 586 psig Coincident with Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Safety Injection (continued)

(d) Except when all MSIVs are closed and de-activated.

(f) Table 3.3.2-1 Notes 1 and 2 are applicable.

Point Beach 3.3.2-8 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 4)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE REQUIRED SURVEILLANCE ALLOWABLE NOMINAL TRIP FUNCTION MODES CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

5. Feedwater Isolation

a. Automatic 2 trains G SR 3.3.2.2 NA NA Actuation Logic 1,2(e),3(e) SR 3.3.2.4 and Actuation SR 3.3.2.5 Relays

b. SG Water Level 3 per SG D SR 3.3.2.1 90% 78%

High 1,2(e),3(e) SR 3.3.2.3(f)

SR 3.3.2.8(f)

c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

6. Auxiliary Feedwater

a. Automatic 1,2,3 2 trains G SR 3.3.2.2 NA NA Actuation Logic and Actuation Relays

b. SG Water Level 1,2,3 3 per SG D SR 3.3.2.1 29.5% 31%

Low Low SR 3.3.2.3(f)

SR 3.3.2.8(f)

c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

d. Undervoltage Bus 1,2 2 per bus H SR 3.3.2.6 3120 V 3255 V A01 and A02 SR 3.3.2.8(f)

e. AFW Pump 1,2,3 1 per pump J SR 3.3.2.1 > 5.8 psig 6.1 psig Suction SR 3.3.2.3(f)

Transfer on SR 3.3.2.8(f)

Suction Pressure - Low

7. SI Block-Pressurizer 1,2,3 3 I SR 3.3.2.1 2005 psig 2000 psig Pressure SR 3.3.2.3 SR 3.3.2.8 (e) Except when all MFIVs, MFRVs and associated bypass valves are closed and de-activated.

(f) Table 3.3.2-1 Notes 1 and 2 are applicable.

Point Beach 3.3.2-9 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 4)

Engineered Safety Feature Actuation System Instrumentation Note 1:

If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

Note 2:

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in FSAR Section 7.2.

Point Beach 3.3.2-10 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Pressurizer PORVs 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

LCO 3.4.11 Each PORV and associated block valve shall be OPERABLE.

APPLICABILITY: MODES 1, 2, MODE 3 with RCS average temperature (T avg )

500°F.

ACTIONS

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

Separate Condition entry is allowed for each PORV and each block valve.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more PORVs A.1 Close and maintain 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable and capable power to associated of being manually block valve.

cycled.

B. One PORV inoperable B.1 Close associated block 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and not capable of valve.

being manually cycled.

AND B.2 Remove power from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated block valve.

AND B.3 Restore PORV to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.4.11-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Pressurizer PORVs 3.4.11 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One block valve -----------------NOTE-----------------

inoperable. Required Actions C.1 and C.2 do not apply when block valve is inoperable solely as a result of complying with Required Actions B.2 or E.2 C.1 Place associated PORV 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in manual control.

AND C.2 Restore block valve to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program D. Required Action and D.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A, B, AND or C not met.

D.2 Reduce T avg to < 500°F. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued)

Point Beach 3.4.11-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Pressurizer PORVs 3.4.11 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. Two PORVs inoperable E.1 Close associated block 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and not capable of being valves.

manually cycled.

AND E.2 Remove power from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated block valves.

AND E.3 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AND E.4 Reduce T avg to < 500°F. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months F. Two block valves -----------------NOTE-----------------

inoperable. Required Action F.1 does not apply when block valve is inoperable solely as a result of complying with Required Actions B.2 or E.2 F.1 Restore one block valve 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to OPERABLE status.

G. Required Action and G.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition F not AND met.

G.2 Reduce T avg to < 500°F. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Point Beach 3.4.11-3 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Pressurizer PORVs 3.4.11 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1 ---------------------------NOTE--------------------------

Not required to be met with block valve closed in accordance with the Required Action of Condition B or E.

In accordance with the Perform a complete cycle of each block valve. Surveillance Frequency Control Program SR 3.4.11.2 Perform a complete cycle of each PORV. In accordance with the Surveillance Frequency Control Program Point Beach 3.4.11-4 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ECCS Operating 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS Operating LCO 3.5.2 Two ECCS trains shall be OPERABLE.

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

In MODE 3, both safety injection (SI) pump flow paths may be isolated by closing the isolation valves for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to perform pressure isolation valve testing per SR 3.4.14.1.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One ECCS train A.1 Restore train to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Point Beach 3.5.2-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ECCS Operating 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.1 -------------------------NOTE-------------------------

Not required to be met for system vent flow paths opened under administrative controls.

Verify each ECCS manual, power operated, and In accordance automatic valve in the flow path, that is not with the locked, sealed, or otherwise secured in position, Surveillance is in the correct position. Frequency Control Program SR 3.5.2.2 Verify ECCS locations susceptible to gas In accordance accumulation are sufficiently filled with water. with the Surveillance Frequency Control Program SR 3.5.2.3 Verify each ECCS pump's developed head at the In accordance test flow point is greater than or equal to the with the required developed head. INSERVICE TESTING PROGRAM SR 3.5.2.4 Verify each ECCS automatic valve in the flow In accordance path that is not locked, sealed, or otherwise with the secured in position, actuates to the correct Surveillance position on an actual or simulated actuation Frequency signal. Control Program (continued)

Point Beach 3.5.2-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ECCS Operating 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.2.5 Verify each ECCS pump starts automatically on In accordance an actual or simulated actuation signal. with the Surveillance Frequency Control Program SR 3.5.2.6 Verify, by visual inspection, each ECCS train In accordance containment sump suction inlet is not restricted with the by debris and the suction inlet debris screens Surveillance show no evidence of structural distress or Frequency abnormal corrosion. Control Program Point Beach 3.5.2-3 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Containment Air Locks 3.6.2 A CTIONS CONDITIONS REQUIRED ACTION COMPLETION TIME B. (continued) B.3 -----------NOTE-----------

Bulkhead doors and equalizing valves in high radiation areas may be verified locked closed by administrative means.

Verify the bulkhead Once per 31 days door and equalizing valve on an OPERABLE bulkhead in the affected airlock are locked closed.

C. One or more C.1 Initiate action to Immediately containment air locks evaluate overall inoperable for reasons containment leakage other than Condition A rate per LCO 3.6.1.

or B.

AND C.2 Verify a bulkhead door 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and associated equalizing valve are closed in the affected air lock.

AND C.3 Restore air lock to 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.6.2-4 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Containment Air Locks 3.6.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND D.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.1 -------------------------NOTES--------------------------

1. An inoperable air lock bulkhead does not invalidate the previous successful performance of the overall air lock leakage test.

2. Results shall be evaluated against acceptance criteria applicable to SR 3.6.1.1.

Perform required air lock leakage rate testing in In accordance accordance with the Containment Leakage Rate with the Testing Program. Containment Leakage Rate Testing Program SR 3.6.2.2 Verify only one bulkhead door and its associated In accordance equalizing valve in the air lock can be opened at with the a time. Surveillance Frequency Control Program Point Beach 3.6.2-5 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Containment Isolation Valves 3.6.3 3.6 CONTAINMENT SYSTEMS 3.6.3 Containment Isolation Valves LCO 3.6.3 Each containment isolation valve shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS

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

1. Penetration flow path(s) except for the purge supply and exhaust flow paths may be unisolated intermittently under administrative controls.

2. Separate Condition entry is allowed for each penetration flow path.

3. Enter applicable Conditions and Required Actions for systems made inoperable by containment isolation valves.

4. Enter applicable Conditions and Required Actions of LCO 3.6.1, "Containment,"

when isolation valve leakage results in exceeding the overall containment leakage rate acceptance criteria.

CONDITION REQUIRED ACTION COMPLETION TIME A. -----------NOTE----------- A.1 Isolate the affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Only applicable to penetration flow path by penetration flow paths use of at least one OR with two containment closed and de-activated isolation valves. automatic valve, closed In accordance

manual valve, blind with the Risk flange, or check valve Informed One or more penetration with flow through the Completion Time flow paths with one valve secured. Program containment isolation valve inoperable. AND (continued)

Point Beach 3.6.3-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Containment Isolation Valves 3.6.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 ----------NOTES----------

1. Isolation devices in high radiation areas may be verified by use of administrative means.

2. Isolation devices that are locked, sealed or otherwise secured may be verified by use of administrative means.

Verify the affected Once per 31 days penetration flow path is following isolation isolated. for isolation devices outside containment AND Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days for isolation devices inside containment B. -----------NOTE----------- B.1 Isolate the affected 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Only applicable to penetration flow path by penetration flow paths use of at least one with two containment closed and de-activated isolation valves. automatic valve, closed

manual valve, or blind flange.

One or more penetration flow paths with two containment isolation valves inoperable.

(continued)

Point Beach 3.6.3-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Containment Isolation Valves 3.6.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. -----------NOTE----------- C.1 Isolate the affected 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Only applicable to penetration flow path by penetration flow paths use of at least one OR with only one closed and de-activated containment isolation automatic valve, closed In accordance valve and a closed manual valve, or blind with the Risk system. flange. Informed

Completion Time AND Program One or more penetration flow paths with one C.2 -----------NOTES----------

containment isolation 1. Isolation devices in high valve inoperable. radiation areas may be verified by use of administrative means.

2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means.

Verify the affected Once per 31 days penetration flow path following isolation is isolated. for isolation devices outside containment AND Prior to entering Mode 4 from Mode 5 if not performed within the previous 92 days for isolation devices inside containment (continued)

Point Beach 3.6.3-3 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

MSIVs and Non-Return Check Valves 3.7.2 3.7 PLANT SYSTEMS 3.7.2 Main Steam Isolation Valves (MSIVs) and Non-Return Check Valves LCO 3.7.2 Two MSIVs and two non-return check valves shall be OPERABLE.

APPLICABILITY: MODES 1, 2 and 3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One Steam Generator A.1 Restore valve to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months flowpath with one or OPERABLE status.

more inoperable valves OR in MODE 1.

NOTE-------

Not applicable when more than one valve inoperable in one SG flowpath.

In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not met.

(continued)

Point Beach 3.7.2-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

MSIVs and Non-Return Check Valves 3.7.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. -----------NOTE----------- -------------------NOTE-------------------

Separate Condition An inoperable flowpath may be entry is allowed for each opened under administrative Steam Generator flowpath. controls to allow cool down of the

affected unit.

One or both MSIVs C.1 Close and de-activate 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months inoperable in MODE 2 the MSIV in the affected or 3. flowpath.

OR AND One or both non-return C.2 Close non-return 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months check valves inoperable check valve in the in MODE 2 or 3. affected flowpath.

AND C.3 Verify MSIV and non- Once per 7 days return check valve in the affected flowpath are closed and the MSIV is de-activated.

D. Required Action and D.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition C not AND met.

D.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Point Beach 3.7.2-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

MSIVs and Non-Return Check Valves 3.7.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.2.1 --------------------------NOTE-------------------------

Only required to be performed in MODE 1.

Verify closure time of each MSIV is within limits. In accordance with the INSERVICE TESTING PROGRAM SR 3.7.2.2 --------------------------NOTE-------------------------

Only required to be performed in MODE 1.

In accordance Verify each MSIV actuates to the isolation with the position on an actual or simulated actuation Surveillance signal. Frequency Control Program SR 3.7.2.3 Verify each main steam non-return check valve In accordance can close. with the INSERVICE TESTING PROGRAM Point Beach 3.7.2-3 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

ADV Flowpaths 3.7.4 3.7 PLANT SYSTEMS 3.7.4 Atmospheric Dump Valve (ADV) Flowpaths LCO 3.7.4 Two ADV flowpaths shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, MODE 4 when steam generator is relied upon for heat removal.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required ADV A.1 Restore required ADV 7 days flowpath inoperable. flowpath to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program B. Two required ADV B.1 Restore one ADV 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months flowpaths inoperable. flowpath to OPERABLE status.

C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND C.2 Be in MODE 4 without 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months reliance upon steam generator for heat removal.

Point Beach 3.7.4-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AFW System 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Auxiliary Feedwater (AFW)

LCO 3.7.5 The AFW System shall be OPERABLE with; one turbine driven AFW pump system and one motor driven AFW pump system:

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

Only the motor driven AFW pump system is required to be OPERABLE in MODE 4.

APPLICABILITY: MODES 1, 2, and 3, MODE 4 when steam generator is relied upon for heat removal.

ACTIONS

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

LCO 3.0.4.b is not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. Turbine driven AFW A.1 Restore affected 7 days pump system inoperable equipment to due to one inoperable OPERABLE status. OR steam supply.

In accordance OR with the Risk Informed

NOTE------------ Completion Time Only applicable if Program MODE 2 has not been entered following refueling.

Turbine driven AFW pump system inoperable in MODE 3 following refueling.

(continued)

Point Beach 3.7.5-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AFW System 3.7.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One AFW pump system B.1 Restore AFW pump 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable in MODE 1, 2 system to OPERABLE or 3 for reasons other status. OR than Condition A.

In accordance with the Risk Informed Completion Time Program C. Turbine driven AFW C.1 Restore the steam 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months pump system inoperable supply to the turbine due to one inoperable driven pump system to steam supply. OPERABLE status.

AND OR OR Motor driven AFW pump system inoperable. C.2 Restore the motor 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months if motor driven AFW pump driven AFW pump system to OPERABLE system is status. available from the opposite unit.

(continued)

Point Beach 3.7.5-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

CC System 3.7.7 3.7 PLANT SYSTEMS 3.7.7 Component Cooling Water (CC) System LCO 3.7.7 The CC System shall be OPERABLE with; two CC pumps, and two required CC heat exchangers.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS

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

Enter applicable Conditions and Required Actions of LCO 3.4.6, "RCS Loops MODE 4," for residual heat removal loops made inoperable by CC.

CONDITION REQUIRED ACTION COMPLETION TIME A. One CC pump A.1 Restore CC pump to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program B. One required CC heat B.1 Restore required CC 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months exchanger inoperable. heat exchanger to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.7.7-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

CC System 3.7.7 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND C.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 --------------------------NOTE-------------------------

Isolation of CC flow to individual components does not render the CC System inoperable.

In accordance with the Verify each CC manual, power operated, and Surveillance automatic valve in the flow path servicing Frequency safety related equipment, that is not locked, Control Program sealed, or otherwise secured in position, is in the correct position.

Point Beach 3.7.7-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

SW System 3.7.8 3.7 PLANT SYSTEMS 3.7.8 Service Water (SW) System LCO 3.7.8 The SW System shall be OPERABLE with:

a. Six OPERABLE SW pumps;

b. SW ring header continuous flowpath not interrupted;

c. Required automatic non-essential-SW-load isolation valves OPERABLE or affected non-essential flowpath isolated; and

d. Opposite unit containment accident fan cooler unit SW outlet motor operated valves closed or SW flowpath isolated.

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

Only five SW pumps are required to be OPERABLE with one unit in MODE 5 or 6, or defueled, and the SW System capable of providing required cooling water flow to required equipment.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS

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

Enter applicable Conditions and Required Actions for systems made inoperable by SW System.

CONDITION REQUIRED ACTION COMPLETION TIME A. One SW pump A.1 Restore SW pump to 7 days inoperable. OPERABLE status.

OR AND In accordance Both units in MODES 1, with the Risk 2, 3, or 4. Informed Completion Time Program (continued)

Point Beach 3.7.8-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

SW System 3.7.8 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Two or three SW pumps B.1 Restore SW pump(s) to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. OPERABLE status.

C. SW ring header C.1 Verify SW System 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months continuous flowpath capable of providing interrupted. required cooling water flow to required equipment.

AND C.2 Restore the SW ring 7 days header continuous flowpath. OR In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.7.8-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

SW System 3.7.8 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. ----------NOTE--------- D.1 -----------NOTE----------

Separate Condition Not required to be met entry is allowed for if in Condition E.

each non-essential- -----------------------------

SW-load flowpath.

Verify required redundant 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months automatic isolation valve One or more in the affected non-non-essential-SW- essential flowpath(s) load flowpath(s) with OPERABLE.

one required automatic isolation AND valve inoperable.

D.2 Isolate the affected non- 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months AND essential flowpath(s).

OR Affected non-essential flowpath(s) In accordance not isolated. with the Risk Informed Completion Time Program E. One or more E.1 Isolate the affected non- 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months non-essential-SW-load essential flowpath(s).

flowpath(s) with two required automatic isolation valves inoperable.

AND Affected non-essential flowpath(s) not isolated.

(continued)

Point Beach 3.7.8-3 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

SW System 3.7.8 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME F. One or more opposite F.1 Verify SW System 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months unit containment capable of providing accident fan cooler unit required cooling water SW outlet motor flow to required operated valves open. equipment.

AND AND Opposite unit F.2 Isolate the opposite unit 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months containment accident fan containment accident fan cooler unit SW flowpath cooler unit SW flowpath. AND not isolated.

14 days from discovery of failure to meet the LCO G. Four or more SW pumps G.1 Restore SW pump(s) to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. OPERABLE status.

H. Required Action and H.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND H.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Point Beach 3.7.8-4 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

SW System 3.7.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.8.1 ---------------------------NOTE---------------------------

Isolation of SW flow to individual components does not render the SW System inoperable.

In accordance with the Verify each SW manual, power operated, and Surveillance automatic valve in the flow path servicing safety Frequency related equipment, that is not locked, sealed, or Control Program otherwise secured in position, is in the correct position.

SR 3.7.8.2 Verify each required SW automatic non-essential- In accordance SW-load isolation valve that is not locked, with the sealed, or otherwise secured in the closed Surveillance position, actuates to the closed position on an Frequency actual or simulated actuation signal. Control Program SR 3.7.8.3 Verify each SW pump starts automatically on an In accordance actual or simulated actuation signal. with the Surveillance Frequency Control Program Point Beach 3.7.8-5 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 Verify gas turbine in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months operation.

OR In accordance with the Risk Informed Completion Time Program B. Associated unit's 13.8/4.16 B.1 Restore associated 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months kV (X04) transformer unit's 13.8/4.16 kV (X04) inoperable. transformer to OR OPERABLE status.

In accordance with the Risk Informed Completion Time Program C. Associated unit's required C.1 Restore required offsite 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months offsite power source to power source(s) to buses A05 and A06 OPERABLE status. OR inoperable.

In accordance OR with the Risk Informed Required offsite power Completion source to buses 1A05 and Time Program 2A06 inoperable.

(continued)

Point Beach 3.8.1-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 A CTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One or more required D.1 Declare required 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from offsite power source(s) to feature(s) supported by discovery of one or more required Class the inoperable required Condition D 1E 4.16 kV bus(es) offsite power source concurrent with inoperable. inoperable when its inoperability of required redundant redundant required feature(s) is inoperable. feature(s)

AND D.2 Restore required offsite 7 days power source(s) to OPERABLE status. OR

NOTE--------

Not applicable when more than one offsite power source inoperable or when one offsite power source to more than one required Class 1E 4.16kV bus inoperable.

In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.8.1-3 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 A CTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

NOTE------------ E.1 Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from Separate Condition entry is feature(s) supported by discovery of allowed for each the inoperable standby Condition E inoperable standby emergency power concurrent with emergency power source. source inoperable when inoperability of

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

E. One or more required standby emergency power AND source(s) inoperable.

E.2.1 Determine other 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months required standby emergency power source(s) is not inoperable due to common cause failure.

OR E.2.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months other required standby emergency power source(s).

OR E.2.3 Declare other required 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months standby emergency power source(s) inoperable.

AND E.3 Restore required standby 7 days emergency power source(s) to OPERABLE AND status.

14 days from discovery of failure to meet LCO (continued)

Point Beach 3.8.1-4 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 A CTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

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

F. One or more required Enter applicable Conditions and offsite power source to one Required Actions of LCO 3.8.9, or more Class 1E 4.16 kV "Distribution SystemsOperating,"

safeguards bus(es) when Condition F is entered with inoperable.

no AC power to any train.

AND F.1 Restore required offsite 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Standby emergency power circuit to OPERABLE inoperable to redundant status. OR equipment.

NOTE--------

Not applicable when more than one offsite power source inoperable or when one offsite power source to more than one Class 1E 4.16kV safeguard bus inoperable.

In accordance with the Risk Informed Completion Time Program (continued)

Point Beach 3.8.1-5 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 A CTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. (continued) OR F.2 Restore required 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months standby emergency power source to OR OPERABLE status.

NOTE--------

Not applicable when more than one offsite power source inoperable or when one offsite power source to more than one Class 1E 4.16kV safeguard bus inoperable.

In accordance with the Risk Informed Completion Time Program G. Standby emergency power G.1 Restore one required 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to buses 1A05/1B03 and standby emergency 1A06/1B04 inoperable. power source to OPERABLE status.

OR Standby emergency power to buses 2A05/2B03 and 2A06/2B04 inoperable.

OR Standby emergency power to buses 1A05/1B03 and 2A06/2B04 inoperable.

(continued)

Point Beach 3.8.1-6 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 A CTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME H. Required Action and H.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND H.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated In accordance with power availability for each required offsite circuit. the Surveillance Frequency Control Program SR 3.8.1.2 ---------------------------NOTES--------------------------

1. All standby emergency power source starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.

2. A modified standby emergency power source start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.

In accordance with Verify each standby emergency power source the Surveillance starts from standby conditions and achieves Frequency Control rated voltage and frequency. Program (continued)

Point Beach 3.8.1-7 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 --------------------------NOTES--------------------------

1. Standby emergency power source loadings may include gradual loading.

2. Momentary transients outside the load range do not invalidate this test.

3. This SR shall be preceded by and immediately follow without shutdown a successful performance of SR 3.8.1.2.

In accordance with Verify each standby emergency power source is the Surveillance synchronized and loaded and operates for Frequency Control 60 minutes at a load 2500 kW and Program 2850 kW.

SR 3.8.1.4 Verify the fuel oil transfer system operates to In accordance with automatically transfer fuel oil from storage tank to the Surveillance the day tank. Frequency Control Program (continued)

Point Beach 3.8.1-8 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.5 -------------------------NOTE-----------------------------

This surveillance shall not normally be performed with the associated unit in MODE 1, 2, 3, or 4.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify on an actual or simulated loss of offsite In accordance with power signal in conjunction with an actual or the Surveillance simulated ESF actuation signal: Frequency Control Program

a. De-energization of emergency buses;

b. Load shedding from emergency buses; and

c. Standby emergency power source auto-starts from standby condition and:

1. energizes permanently connected loads,

2. energizes auto-connected emergency loads through load logic and sequencer,

3. achieves steady state voltage within limits,

4. achieves steady state frequency within limits, and

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

(continued)

Point Beach 3.8.1-9 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.6 Verify each standby emergency power source: In accordance with the Surveillance

a. Synchronizes with offsite power source Frequency Control while loaded with emergency loads upon a Program simulated restoration of offsite power;

b. Transfers loads to offsite power source; and

c. Returns to ready-to-load operation.

SR 3.8.1.7 -----------------------NOTES-------------------------------

1. Momentary transients outside the load and power factor ranges do not invalidate this test.

2. This Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

3. If performed with the standby emergency power source synchronized with offsite power, it shall be performed at a power factor < 0.87. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition, the power factor shall be maintained as close to the limit as practicable.

In accordance with Verify each standby emergency power source the Surveillance operates for > 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at > 2850 kW (G01/G02), Frequency Control

> 2848 kW (G03/04). Program Point Beach 3.8.1-10 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

DC SourcesOperating 3.8.4 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC SourcesOperating LCO 3.8.4 The D-01, D-02, D-03, and D-04 DC electrical power subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One DC electrical power -----------------NOTE----------------

subsystem inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems Operating," when any DC bus is de-energized.

A.1 Restore DC electrical 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months power subsystem to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Associated Completion Time not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Point Beach 3.8.4-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

DC SourcesOperating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify correct battery terminal voltage is within In accordance limits on float charge. with the Surveillance Frequency Control Program SR 3.8.4.2 Verify no visible corrosion at battery terminals In accordance and connectors. with the Surveillance OR Frequency Control Program Verify battery connection resistance is within limits.

SR 3.8.4.3 Verify battery cells, cell plates, and racks show In accordance no visual indication of physical damage or with the abnormal deterioration that could degrade Surveillance battery performance. Frequency Control Program SR 3.8.4.4 Remove visible terminal corrosion, and verify In accordance battery cell to cell and terminal connections are with the coated with anti-corrosion material. Surveillance Frequency Control Program SR 3.8.4.5 Verify battery connection resistance is within In accordance limits. with the Surveillance Frequency Control Program (continued)

Point Beach 3.8.4-2 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

InvertersOperating 3.8.7 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 InvertersOperating LCO 3.8.7 Four inverters shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required inverter A.1 -----------NOTE------------

inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems - Operating" with any vital bus de-energized.

Restore inverter to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months OPERABLE status.

OR In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Point Beach 3.8.7-1 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.7 Risk Informed Completion Time Program This program provides controls to calculate a Risk Informed Completion Time (RICT) and must be implemented in accordance with NEI 06-09, Risk-Informed Technical Specifications Initiative 4b: Risk-Managed Technical Specifications (RMTS) Guidelines, Revision 0-A, November 2006. The program shall include the following:

a. The RICT may not exceed 30 days;

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

c. When a RICT is being used, any change to the plant configuration, as defined in NEI 06-09-A, 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 Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

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

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

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

2. Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.

Point Beach 5.5-6 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.7 Risk Informed Completion Time Program (continued)

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, 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.

5.5.8 Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following:

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the as found condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The as found condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes.

Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

b. Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1. Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down), and all anticipated transients included in the design specification, and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to Point Beach 5.5-7 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) (continued) determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 500 gallons per day per SG.

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, RCS Operational LEAKAGE.

c. Provisions for SG tube plugging criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

The following alternate tube plugging criteria shall be applied as an alternative to the 40% depth based criteria:

For Unit 1 only, tubes with service-induced flaws located greater than 20.6 inches below the top of the tubesheet do not require plugging.

Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 20.6 inches below the top of the tubesheet shall be plugged upon detection.

This alternate tube plugging criteria is not applicable to the tube at row 38 column 69 in the A steam generator, which is not expanded in the hot leg the full length of the tubesheet. This tube has been removed from service by plugging (during U1R31).

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. For Unit 1, the number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube from 20.6 inches below the top of the tubesheet on the hot leg side to 20.6 inches below the top of the Point Beach 5.5-8 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) (continued) tubesheet on the cold leg side and that may satisfy the applicable tube plugging criteria. For Unit 2, the number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube plugging criteria.

For Unit 1 and Unit 2: The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. A degradation assessment shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what location.

1. Inspect 100% of the tubes in each SG during the first refueling outage following SG installation.

2. i. Unit 1 (alloy 600 Thermally Treated tubes): After the first refueling outage following SG installation, inspect each SG at least every 48 effective full power months or at least every other refueling outage (whichever results in more frequent inspections). In addition, the minimum number of tubes inspected at each scheduled inspection shall be the number of tubes in all SGs divided by the number of SG inspection outages scheduled in each inspection period as defined in a, b, and c below. If a degradation assessment indicates the potential for a type of degradation to occur at a location not previously inspected with a technique capable of detecting this type of degradation at this location and that may satisfy the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and Point Beach 5.5-9 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) (continued) the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a) After the first refueling outage following SG installation, inspect 100% of the tubes during the next 120 effective full power months.

This constitutes the first inspection period; b) During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the second inspection period; and c) During the remaining life of the SGs, inspect 100% of the tubes every 72 effective full power months. This constitutes the third and subsequent inspection periods.

ii. Unit 2 (alloy 690 Thermally Treated tubes): After the first refueling outage following SG installation, inspect each SG at least every 72 effective full power months or at least every third refueling outage (whichever results in more frequent inspections). In addition, the minimum number of tubes inspected at each scheduled inspection shall be the number of tubes in all SGs divided by the number of SG inspection outages scheduled in each inspection period as defined in a, b, c and d below. If a degradation assessment indicates the potential for a type of degradation to occur at a location not previously inspected with a technique capable of detecting this type of degradation at this location and that may satisfy the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

Point Beach 5.5-10 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) (continued) a) After the first refueling outage following SG installation, inspect 100% of the tubes during the next 144 effective full power months.

This constitutes the first inspection period; b) During the next 120 effective full power months, inspect 100% of the tubes. This constitutes the second inspection period; c) During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the third inspection period; and d) During the remaining life of the SGs, inspect 100% of the tubes every 72 effective full power months. This constitutes the fourth and subsequent inspection periods.

3. For Unit 1, if crack indications are found in any SG tube from 20.6 inches below the top of the tubesheet on the hot leg side to 20.6 inches below the top of the tubesheet on the cold leg side, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever results in more frequent inspections). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

For Unit 2, if crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever results in more frequent inspections). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE.

Point Beach 5.5-11 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables;

b. Identification of the procedures used to measure the values of the critical variables;

c. Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser in leakage;

d. Procedures for the recording and management of data;

e. Procedures defining corrective actions for all off control point chemistry conditions; and

f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

5.5.10 Ventilation Filter Testing Program (VFTP)

A program shall be established to implement the following required testing of the Control Room Emergency Filtration System (F-16) at the frequencies specified in Regulatory Guide 1.52, Revision 2, and in accordance with ASTM D3803-1989 and the methodology of ANSI N510-1980, as prescribed below.

a. Demonstrate for the Control Room Emergency Filtration System (F-16) that an inplace test of the high efficiency particulate air (HEPA) filters shows a penetration and system bypass <1.0%

when tested in accordance with the methodology of ANSI N510-1980, Section 10, excluding subsection 10.3, at a system flowrate of 4950 cfm +/- 10%.

b. Demonstrate for the Control Room Emergency Filtration System (F-16) that an inplace test of the charcoal adsorber shows a penetration and system bypass < 1.0% when tested in accordance with the methodology of ANSI N510-1980, Section 12, excluding subsection 12.3, at a system flowrate of 4950 cfm +/- 10%.

Point Beach 5.5-12 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Ventilation Filter Testing Program (VFTP) (continued)

c. Demonstrate for the Control Room Emergency Filtration System (F-16) that a laboratory test of a sample of the charcoal adsorber, when obtained in accordance with the methodology of ANSI N510-1980, Section 13, excluding subsection 12.3, shows the methyl iodide penetration < 2.5%, when tested in accordance with ASTM D3803-1989 at a temperature of 30°C and a relative humidity of 95%, applying the tolerances of ASTM D3803-1989.

d. Demonstrate for the Control Room Emergency Filtration System (F-16) that the pressure drop across the combined HEPA filters and the charcoal adsorbers is less than 6 inches of water when tested in accordance with the methodology of ANSI N510-1980, Sections 10 and 12, excluding subsections 10.3 and 12.3, at a system flowrate of 4950 cfm +/- 10%.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

5.5.11 Explosive Gas Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the on-service Gas Decay Tank.

The program shall include a limit for oxygen concentration in the on-service Gas Decay Tank 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 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas Monitoring Program surveillance frequencies.

Point Beach 5.5-13 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:

a. Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has:

1. an API gravity or an absolute specific gravity within limits,

2. a flash point and kinematic viscosity within limits for ASTM 2D fuel oil, and

3. a clear and bright appearance with proper color;

b. Within 31 days of addition of the new fuel oil to storage tanks verify that the properties of the new fuel oil, other than those addressed in

a. above, are within limits for ASTM 2D fuel oil; and

c. Total particulate concentration of the fuel oil is < 10 mg/l when tested every 92 days in accordance with the applicable ASTM standard.

d. The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test frequencies.

5.5.13 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b. Licensees may make changes to Bases without prior NRC approval provided the changes do not involve either of the following:

1. a change in the TS incorporated in the license; or

2. a change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

Point Beach 5.5-14 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Technical Specifications (TS) Bases Control Program (continued)

c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the FSAR.

d. Proposed changes that meet the criteria of Specification 5.5.13b above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

5.5.14 Safety Function Determination Program (SFDP)

This program ensures loss of safety function is detected and appropriate actions taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:

a. Provisions for cross train checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected;

b. Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;

c. Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and

d. Other appropriate limitations and remedial or compensatory actions.

Point Beach 5.5-15 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Safety Function Determination Program (SFDP) (continued)

A loss of safety function exists when, assuming no concurrent single failure, and assuming no concurrent loss of offsite power or loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.15 Containment Leakage Rate Testing Program

a. A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with Nuclear Energy Institute (NEI) 94-01, Revision 3-A, Industry Guidance for Implementing Performance Based Option of 10 CFR 50, Appendix J, and the conditions and limitations specified in NEI 94-01, Revision 2-A.

Point Beach 5.5-16 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Containment Leakage Rate Testing Program (continued)

b. The peak design containment internal accident pressure, P a , is 60 psig.

c. The maximum allowable containment leakage rate, L a at P a , shall be 0.2% of containment air weight per day.

d. Leakage rate acceptance criteria are:

1. Containment leakage rate acceptance criterion is < 1.0 L a .

2. During the first unit startup following testing in accordance with this program, the leakage rate acceptance are < 0.6 L a for the combined Type B and Type C tests and < 0.75 L a for the Type A tests.

3. Air lock testing acceptance criteria are:

i. Overall air lock leakage rate is < 0.05 L a when tested at >

P a.

ii. For each door seal, leakage rate is equivalent to < 0.02 L a at > P a when tested at a differential pressure of > to 10 inches of Hg .

e. The provisions of SR 3.0.2 do not apply to the test frequencies in the Containment Leakage Rate Testing Program.

f. The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

Point Beach 5.5-17 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 Reactor Coolant System (RCS) Pressure Isolation Valve (PIV)

Leakage Program A program shall be established to verify the leakage from each RCS PIV is within the limits specified below, in accordance with the Event V Order, issued April 20, 1981.

a. Minimum differential test pressure shall not be less than 150 psid.

b. Leakage rate acceptance criteria are:

1. Leakage rates less than or equal to 1.0 gpm are considered acceptable.

2. Leakage rates greater than 1.0 gpm but less than or equal to 5.0 gpm are considered acceptable if the latest measured rate has not exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gpm by 50% or greater.

3. Leakage rates greater than 1.0 gpm but less than or equal to 5.0 gpm are considered unacceptable if the latest measured rate exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gpm by 50% or greater.

4. Leakage rates greater than 5.0 gpm are considered unacceptable.

5.5.17 Pre-Stressed Concrete Containment Tendon Surveillance Program This program provides controls for monitoring any tendon degradation in pre-stressed concrete containments, including effectiveness of its corrosion protection medium, to ensure containment structural integrity.

The program shall include baseline measurements prior to initial operations. The Tendon Surveillance Program, inspection frequencies, and acceptance criteria shall be in accordance with Regulatory Guide 1.35, Revision 3, 1990.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Tendon Surveillance Program inspection frequencies.

Point Beach 5.5-18 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.18 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Filtration System (CREFS), CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident. Additionally, separate from the CREFS, the program shall ensure CRE occupants can maintain the reactor in a safe condition following a hazardous chemical release or smoke challenge. The program shall include the following elements:

a. The definition of the CRE and the CRE boundary.

b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.

c. Requirements for (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors," Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0.

d. Measurement, at designated locations, of the CRE Pressure relative to all external areas adjacent to the CRE boundary during the technical specification emergency mode of operation by the CREFS, operating at the flow rate required by the VFTP, at a Frequency of 18 months. The results shall be trended at a frequency of 18 months and used as part of the periodic assessment of the CRE boundary.

e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in Paragraph c.

The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences.

f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressure and assessing the CRE boundary as required by Paragraphs c and d, respectively.

Point Beach 5.5-19 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.18 Control Room Envelope Habitability Program (continued)

g. An adequate supply of self contained breathing apparatus (SCBA) units in the CRE to protect CRE occupants from a hazardous chemical release.

h. Portable smoke ejection equipment per the Fire Protection Evaluation Report and Safe Shutdown Analysis Report to address a potential smoke challenge.

5.5.19 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operations are met:

a. The Surveillance Frequency Control Program shall contain a list of frequencies of those Surveillance Requirements for which the frequency is controlled by the program.

b. Changes to the frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, Risk-Informed Method for Control of Surveillance Frequencies, Revision 1.

c. The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the frequencies established in the Surveillance Frequency Control Program.

Point Beach 5.5-20 Unit 1 - Amendment No. 271 Unit 2 - Amendment No. 273

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NOS. 271 AND 273, RESPECTIVELY, TO RENEWED FACILITY OPERATING LICENSE NOS. DPR-24 AND DPR-27 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 DOCKET NOS. 50-266 AND 50-301

1.0 INTRODUCTION

By application dated May 20, 2022 (Reference 1), as supplemented by letters dated July 11, 2022 (Reference 2), January 11, 2023 (Reference 3), and February 21, 2023 (Reference 4), NextEra Energy Point Beach, LLC (NextEra, the licensee) submitted a license amendment request (LAR) for Point Beach Nuclear Plant, Units 1 and 2 (Point Beach).

The amendment would revise technical specification (TS) requirements to permit the use of risk-informed completion times (RICTs) for actions to be taken when limiting conditions for operation (LCOs) are not met. The proposed changes are based on Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, dated July 2, 2018 (Reference 5). The U.S. Nuclear Regulatory Commission (NRC, the Commission) issued a final revised model safety evaluation (SE) to be used when preparing a plant-specific SE of an LAR to adopt TSTF-505, Revision 2, on November 21, 2018 (Reference 6).

The licensee has proposed variations from the TS changes approved in TSTF-505, Revision 2, which are provided in Section 2.4 of attachment 1, Evaluation of Proposed Changes, (Reference 7) to the LAR and evaluated in sections 3.2 and 3.3 of this SE.

The NRC staff participated in a regulatory audit from August 11, 2022, to February 3, 2023, to ascertain the information needed to support its review of the application and to develop requests for additional information (RAIs), as needed. On February 21, 2023, the NRC staff issued an audit summary (Reference 8). Following the regulatory audit, the NRC issued requests for additional information (RAIs) in email correspondence dated December 20, 2022 (Reference 9) and January 31, 2023 (Reference 10).

The supplemental letters of July 11, 2022, January 11, 2023, and February 21, 2023, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register on August 9, 2022 (87 FR 48517).

Enclosure 3

2.0 REGULATORY EVALUATION

2.1 Regulatory Review 2.1.1 Applicable Regulations Title 10 of the Code of Federal Regulations (10 CFR) Part 50 provides the general provisions for Domestic Licensing of Production and Utilization Facilities. The general provisions include but are not limited to establishing the regulatory requirements that a licensee must adhere to for the submittal of a license application. The NRC staff has identified the following applicable sections within 10 CFR Part 50, along with the provision provided in 10 CFR Part 20 for the staffs review of the licensees application to adopt TSTF-505, Revision 2.

Section 50.36, Technical Specifications, of 10 CFR Part 50, paragraphs (c)(2),

Limiting conditions for operation, and (c)(5), Administrative controls Section 50.55a, Codes and Standards, of 10 CFR Part 50, paragraph (h), Protection and safety systems Section 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants (i.e., the Maintenance Rule) of 10 CFR Part 50 10 CFR Part 20, Standards for Protection Against Radiation 2.1.2 Regulatory Guidance NRC Regulatory Guides (RGs) provide one way to ensure that the codified regulations continue to be met. The NRC staff considered the following guidance, along with industry guidance endorsed by the NRC, during its review of the proposed changes:

RG 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment [PRA] Results for Risk-Informed Activities, dated March 2009 (Reference 11).

RG 1.200, Revision 3, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, dated December 2020 (Reference 12).

RG 1.174, Revision 2, An approach for using Probabilistic Risk Assessment I Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, dated May 2011 (Reference 13).

RG 1.174, Revision 3, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, dated January 2018 (Reference 14).

RG 1.177, Revision 0, An Approach for Plant-Specific, Risk-Informed Decision-making:

Technical Specifications, dated August 1998 (Reference 15).

RG 1.177, Revision 2, An Approach for Plant-Specific, Risk-Informed Decision-making:

Technical Specifications, Dated January 2021 (Reference 16).

NUREG-1855, Revision 1, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking, Dated March 2017 (Reference 17).

NUREG-0800, Standard Review Plan [SRP] for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR [light-water reactor] Edition, Chapter 19, Section 19.2, Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance, dated June 2007 (Reference 18), Section 16.0, Technical Specifications, dated March 2010 (Reference 19), and Section 16.1, Risk-Informed Decision Making: Technical Specifications, Dated March 2007 (Reference 20).

Nuclear Energy Institute (NEI) Topical Report NEI 06-09, Revision 0-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS)

Guidelines, dated October 2012 (NEI 06-09-A) (Reference 21), provides guidance for risk-informed TS. The NRC staff issued a final SE approving NEI 06-09 on May 17, 2007 (Reference 22).

The licensees submittal cites RG 1.200, Revision 2, RG 1.174, Revision 2, and RG 1.177, Revision 0. RG 1.200 and RG 1.174 have been updated to Revision 3, and RG 1.177 has been updated to Revision 2. The updates do not include any technical changes that impact the consistency with NEI 06-09-A; therefore, the NRC staff finds the updated revision to RG 1.174 and RG 1.177 also applicable for use in the licensees adoption of TSTF-505, Revision 2.

2.2 Description of Changes 2.2.1 Description of Risk Informed Completion Time Program The TS LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO is not met, the licensee must shut down the reactor or follow any remedial or required action (e.g., testing, maintenance, or repair activity) permitted by the TSs until the condition can be met. The remedial actions (i.e., ACTIONS) associated with an LCO contain conditions that typically describe the ways in which the requirements of the LCO can fail to be met. Specified with each stated Condition are Required Action(s) and Completion Time(s) (CT). The CTs are referred to as the front stops in the context of this SE. For certain conditions, the TSs require exiting the Mode of Applicability of an LCO (i.e., shut down the reactor).

The licensees submittal requested approval to add a RICT Program to the Administrative Controls section of the TSs, and modify selected CTs to permit extending the CTs, provided risk is assessed and managed as described in NEI 06-09-A. The licensee also proposed variations from the TS changes approved in TSTF-505, Revision 2, which are provided in section 2.4 of attachment 1 to the LAR and evaluated in sections 3.2.1 and 3.3 of this SE.

The licensee is proposing no changes to the design of the plant or any operating parameter, and no new changes to the design basis in the proposed changes to the TSs. The effect of the proposed changes when implemented will allow CTs to vary, based on the risk significance of the given plant configuration (i.e., the equipment out of service at any given time), provided that the system(s) retain(s) the capability to perform the applicable safety function(s) without any further failures (e.g., one train of a two-train system is inoperable). These restrictions on inoperability of all required trains of a system ensure that consistency with the defense-in-depth

(DID) philosophy is maintained by following existing guidance when the capability to perform TS safety function(s) is lost.

The proposed RICT Program uses plant specific operating experience for component reliability and availability data. Thus, the allowances permitted by the RICT Program are directly reflective of actual component performance in conjunction with component risk significance.

2.2.2 TS 1.0 Use and Application:

Example 1.3 8, will be added to TS 1.3, Completion Times, and reads as follows:

EXAMPLE 1.3 8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One subsystem A.1 Restore subsystem 7 days inoperable. to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months When a subsystem is declared inoperable, Condition A is entered. The 7 day Completion Time may be applied as discussed in Example 1.3 2. However, the licensee may elect to apply the Risk Informed Completion Time Program which permits calculation of a Risk Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day Completion Time. The RICT cannot exceed 30 days. After the 7 day Completion Time has expired, the subsystem must be restored to OPERABLE status within the RICT or Condition B must also be entered.

The Risk Informed Completion Time Program requires recalculation of the RICT to reflect changing plant conditions. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

If the 7 day Completion Time clock of Condition A has expired and subsequent changes in plant condition result in exiting the applicability of the Risk Informed

Completion Time Program without restoring the inoperable subsystem to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start.

If the RICT expires or is recalculated to be less than the elapsed time since the Condition was entered and the inoperable subsystem has not been restored to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable subsystems are restored to OPERABLE status after Condition B is entered, Condition A is exited, and therefore, the Required Actions of Condition B may be terminated.

3.0 TECHNICAL EVALUATION

For TSTF-505, Revision 2, an acceptable approach for making risk informed decisions about proposed TS changes, including both permanent and temporary changes, is to demonstrate that the proposed licensing basis changes meet the five key principles provided in section C of RG 1.174, Revision 3 and the three-tiered approach outlined in section C of RG 1.177, Revision 2 which supports key principle 4. These key principles and tiers are:

Principle 1: The proposed licensing basis change meets the current regulations unless it is explicitly related to a requested exemption (i.e., a specific exemption under 10 CFR 50.12).

Principle 2: The proposed licensing basis change is consistent with the DID philosophy.

Principle 3: The proposed licensing basis change maintains sufficient safety margins.

Principle 4: When the proposed licensing basis change results in an increase in risk, the increase should be small and consistent with the intent of the Commissions policy statement on safety goals (Reference 23) for the operations of nuclear power plants.

Tier 1: PRA Capability and Insights Tier 2: Avoidance of Risk-Significant Plant Configurations Tier 3: Risk-Informed Configuration Risk Management Principle 5: The impact of the proposed licensing basis change should be monitored by using performance measures strategies.

TSTF-439, Revision 2, Eliminate Second Completion Times Limiting Time From Discovery of Failure to Meet an LCO, (Reference 24) provides an acceptable approach to demonstrate that the proposed licensing basis changes are satisfactory and consists of demonstrating adherence to 10 CFR 50.36(c)(2), 10 CFR 50.36(c)(5), 10 CFR 50.65, and elements included in the Reactor Oversight Process (ROP). The NRC issued a letter approving TSTF-439, Revision 2, on January 11, 2006 (Reference 25).

3.1 Method of Staff Review Each of the key principles and tiers are addressed in NEI 06-09-A and approved in the final model SE issued by the NRC for TSTF-505, Revision 2. NEI 06-09-A provides a methodology for extending existing CTs, and thereby delay exiting the operational mode of applicability or

taking Required Actions if risk is assessed and managed within the limits and programmatic requirements established by a RICT Program. The NRC staffs evaluation of the licensees proposed use of RICTs against the key safety principles of RG 1.174, Revision 3, and RG 1.177, Revision 2, is discussed below.

TSTF-439 provides a method for removing the second CTs and highlights the controls of the monitoring report, the ROP, and the new requirement in Standard Technical Specifications (STS), Section 1.3. The LAR included proposed changes to the TS Bases. Although the TS Bases are not part of the TSs, the NRC staff confirmed that that the TS Bases described the basis for each revised TS requirement accurately, as described in Section 16.0 of NUREG-0800. The NRC staffs evaluation of the licensees proposed removal of the second CTs is provided within key principle 1, section 3.2.1 of this SE. Although TSTF-439 was not submitted as a risk-informed application, NRC staff found that key principles 1 through 3 and the applicability of the monitoring report along with the performance indicators for key principle 5 applied and included their findings on TSTF-439.

3.2 Review of Key Principles 3.2.1 Key Principle 1: Evaluation of Compliance with Current Regulations Paragraph 50.36(c)(2) of 10 CFR Part 50 requires that LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the TS until the condition can be met.

The CTs in the current TSs were established using experiential data, risk insights, and engineering judgement. The RICT Program provides the necessary administrative controls to permit extension of CTs and, thereby, delay reactor shutdown or Required Actions, if risk is assessed and managed appropriately within specified limits and programmatic requirements, and the safety margins and DID remains sufficient. The option to determine the extended CT in accordance with the RICT Program allows the licensee to perform an integrated evaluation in accordance with the methodology identified in NEI 06-09-A and proposed TS 5.5.7, Risk Informed Completion Time Program. The RICT is limited to a maximum of 30 days (termed the back stop).

The typical CT for TSTF-505, Revision 2, is modified by the application of the RICT Program as shown in the following example. The changed portion is indicated in italics.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One subsystem A.1 Restore subsystem 7 days inoperable. to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program

In attachment 1, section 2.4.1, Administrative Variations, item 8 the licensee proposes to delete the second CT from the listed Required Actions that are proposed for inclusion in the RICT Program. Second CTs were included in certain Required Actions to prevent alternating between Conditions in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO, which is inconsistent with the basis of the CTs and is inappropriate. In the supplement dated July 11, 2022, the licensee described the programmatic and administrative controls that are in place which prohibit prolonged periods of failing to satisfy an LCO. Therefore, the licensee shall have administrative controls to limit the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO. These administrative controls shall ensure that the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO is not inappropriately extended. The NRC staff reviewed the proposed changes to the TSs and determined that they meet the requirements set forth in 10 CFR 50.36. Additionally, the changes to the TSs were reviewed for technical clarity and consistency with customary terminology and format in accordance with section 16.0 of NUREG-0800.

In attachment 2, Proposed Technical Specification Changes (Mark-Up), (Reference 26),

attachment 4, Cross-Reference of TSTF-505, Revision 2, and Point Beach Proposed Changes (Reference 27), and enclosure 1, List of Revised Required Actions to Corresponding PRA Functions and Additional Supporting Information, (Reference 28) to the LAR, as supplemented, the licensee provided a list of the TSs, associated LCOs, and Required Actions for the CTs that included modifications and variations from the approved TSTF-505. The modifications and variations consisted of proposed changes to the Required Actions and CTs. Furthermore, consistent with table 1 of TSTF-505 for Point Beach TS 3.3.1.D, TS 3.3.1.Q, TS 3.6.2.C, and TS 3.7.2.A in attachment 5, Evaluation of Plant-Specific Variations, (Reference 29) to the LAR the licensee included additional technical justification to demonstrate the acceptability for including these TSs in the RICT Program. The licensee corrected table E1-1 to accurately reflect the applicable structures, systems and components (SSCs) in TS 3.6.2 Condition C and acknowledged the proposed change is also a plant-specific variation that was inadvertently omitted from the evaluations in attachment 5. The NRC staff reviewed the proposed changes to the TSs, associated LCOs, Required Actions and CTs provided by the licensee for the scope of the RICT Program and removal of second CTs for TSTF-439, Revision 2. The NRC staff concluded that with the incorporation of the RICT Program, existing regulations, and processes, along with administrative controls, the required performance levels of equipment specified in LCOs are not changed, only the required CTs for the Required Actions are modified, such that 10 CFR 50.36(c)(2) will continue to be met. Based on the discussion provided above, the NRC staff finds that for the RICT Program provided in section 2.0 of this SE, LCOs, Required Actions, and CTs meet the first key principle of RG 1.174, Revision 3, and RG 1.177, Revision 2, and therefore is acceptable for meeting the requirements in 10 CFR 50.36.

The licensee proposed the following variation from TSTF-505, Revision 2:

TS 3.6.3 Condition C - Containment System TS 3.6.3 Condition C requires the containment penetration flow path associated with an inoperable containment isolation valve to be isolated within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This is followed by a requirement to periodically verify the penetration is isolated every 31 days and limits the verification to isolation devices located outside containment. In attachment 5 to the LAR the licensee states that the STS of NUREG-1431, Revision 4, Standard Technical Specifications Westinghouse Plants, (Reference 30) in TSTF-505, Revision 2, does not restrict the 31-day verification requirement to only containment isolation valves located outside containment.

However, the NRC staff finds that Point Beach TS 3.6.3, Condition C is equivalent to Condition B of the Westinghouse STS in TSTF-505, Revision 2, and it does restrict the 31-day verification requirement to only containment isolation valves located outside containment. The 31-day verification limitation was an element retained from an earlier version of the Point Beach TS that is consistent with the licensing basis but also differed from the STS version upon which the Point Beach TS are based NUREG-1431, Revision 1, Standard Technical Specifications Westinghouse Plants, (Reference 31) which does not have a restriction associated to only containment isolation valves located outside containment.

The proposed change allows a RICT for isolation of the associated containment penetration but not for the performance of the 31-day penetration isolation verification requirement. By adding the flexibility to use a RICT to determine a time to isolate the penetration, the periodic verification must then be based on the time following isolation. The NRC staff finds this to be a conforming change made to the CT to make it accurate following use of a RICT. The NRC staff finds this change to be acceptable because the 31-day verification requirement is not included in the RICT program, is a conforming change necessary for accurate TS usage, and is consistent with the Point Beach licensing basis. Based on the above, the NRC staff concludes that the proposed variation in TS 3.6.3 is acceptable, and 10 CFR 50.36 will continue to be met.

3.2.2 Key Principle 2: Evaluation of Defense-in-Depth (DID)

In RG 1.174, Revision 3, the NRC identified the following considerations used for evaluation of how the licensing basis change is maintained for the DID philosophy:

Preserve a reasonable balance among the layers of defense.

Preserve adequate capability of design features without an overreliance on programmatic activities as compensatory measures.

Preserve system redundancy, independence, and diversity commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty.

Preserve adequate defense against potential CCFs [common cause failures].

Maintain multiple fission product barriers.

Preserve sufficient defense against human errors.

Continue to meet the intent of the plants design criteria.

The licensee requested to use the RICT Program to extend the existing CTs for the respective TS LCOs prescribed in attachment 2 to the LAR, as supplemented. For the TS LCOs in attachment 5 and enclosure 1 of the LAR, as supplemented, the licensee provided a description and assessment of the redundancy and diversity for the proposed changes. The NRC staffs evaluation of the proposed changes for these LCOs assessed the Point Beachs redundant or diverse means to mitigate accidents to ensure consistency with the plant licensing basis requirements using the guidance in RG 1.174, RG 1.177, and TSTF-505, to ensure adequate DID (for each of the functions) to operate the facility in the proposed manner (i.e., that the changes are consistent with the DID criteria).

Enclosure 1 to the LAR, as supplemented, provided information supporting the Point Beach evaluation of the redundancy, diversity, and DID for each TS LCO and TS Required Action as it relates to instrumentation and control (I&C) and electrical power systems. The NRC confirmed that for the following TS LCOs, the above DID criteria were applicable except for the criteria for maintaining multiple fission product barriers.

TS 3.3.1, Reactor Protection System (RPS) Instrumentation TS 3.3.2, Engineered Safety Feature Actuation System (ESFAS) Instrumentation TS 3.8.1, AC [Alternating Current] Sources - Operating TS 3.8.4, DC [Direct Current] Sources - Operating TS 3.8.7, Inverters - Operating For the TS LCOs specific to I&C (i.e., TS 3.3.1 and 3.3.2), the NRC staff reviewed the specific trip logic arrangements, redundancy, backup systems, manual actions, and diverse trips specified for each of the protective safety functions and associated instrumentation as described in the associated Updated Final Safety Analysis Report (UFSAR) (Reference 32) sections, and as reflected in enclosure 1 of the LAR for each I&C LCO above. The NRC staff verified that, in accordance with the Point Beach UFSAR and equipment and actions credited in enclosure 1 of the LAR, in all applicable operating modes, the affected protective feature would perform its intended function by ensuring the ability to detect and mitigate the associated event or accident when the CT of a channel is extended. Furthermore, the NRC staff concludes that there is sufficient redundancy, diversity, and DID, to protect against common cause failures (CCFs) and potential single failure for the Point Beach instrumentation systems evaluated in LAR enclosure 1 during a RICT. There is at least one diverse means specified by the licensee for initiating mitigating action for each accident event, thus providing DID against a failure of instrumentation during the RICT for each TS LCO. The DID specified by the licensee does not overly rely on manual actions as the diverse means; therefore, there is not over reliance of programmatic activities as compensatory measures. The NRC staff confirmed that the RICT Program would not allow a loss-of-function condition for the design-basis accidents (DBAs) evaluated in the Point Beach UFSAR.

Therefore, the NRC staff finds that the intent of the plants design criteria (e.g., safety functions) for the above TS LCOs related to I&C are maintained.

For the TS LCOs specific to the electrical power systems (i.e., TS 3.8.1, 3.8.4, and 3.8.7), the NRC staff reviewed the electrical power systems design to determine whether there is a potential loss of function (LOF) for each electrical proposed RICT in the LAR based on TSTF-505, with no LOFs identified by the NRC staff. Additionally, the NRC staff reviewed the LAR and its supplements (1) to verify each effected electrical TS LCO can be entered voluntarily or involuntarily based on NEI 06-09-A and (2) to evaluate if the affected electrical power systems for those LCOs could perform their safety functions (assuming no additional failures other than for LCO being implemented) for the proposed RICTs. Based on the NRC staff review, and because the LAR imposes no physical or operational changes on either Point Beach unit, the NRC staff finds that the Point Beach electrical power systems would function as intended with the proposed RICTs. The NRC staff also verified that the design success criteria in enclosure 1 to the LAR, table E1-1 for each of the electrical TS LCOs reflects the minimum operable electrical power sources to support their safety functions to mitigate postulated DBAs, safely shut down the reactor, and maintain the reactor in a safe shutdown condition, and that there are RICT estimates for each of these electrical TS LCOs in enclosure 1 to the LAR table E1-2 consistent with NEI 06-09-A.

In enclosure 12, Risk Management Action Examples, (Reference 33) to the LAR, the licensee provided examples of risk management actions (RMAs) that may be considered during a RICT program entry for the above electrical TS LCO required actions to reduce the risk impact and ensure adequate DID. The NRC staff reviewed the proposed RMA examples which provide reasonable assurance that the actual RMAs implemented to monitor and control risk for each TS LCO will be of similar quality and tailored for that LCO.

The NRC staff reviewed the licensees proposed electrical TS LCO changes and supporting documentation. Based on the evaluation above, the NRC staff finds that given each electrical TS LCOs reduced redundancy, the CT extensions, as allowed by the RICT Program, are acceptable because (a) the capacity and capability of the remaining operable electrical systems to perform their safety functions (assuming no additional failures) is maintained, and (b) the licensees identification and implementation of RMAs as compensatory measures, in accordance with the RICT Program, will be effective.

Licensee Proposed Variations from TSTF-505, Revision 2 The I&C TS LCOs addressed above are also subject to Point Beach variations. These variations are evaluated below. In TSs, I&C functions with a 1-hour CT are typically associated with a LOF condition; therefore, for each 1-hour CT below, the NRC staff confirmed there was not a LOF and therefore it is acceptable to apply a RICT.

TS 3.3.1 Condition D - Power Range Neutron Flux High TS 3.3.1, Condition D, requires the power range neutron flux channel to be placed in tripped position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of inoperability. Condition D differs from the Westinghouse STS in TSTF-505, Revision 2 in not additionally requiring either a thermal power reduction to less than 75 percent Rated Thermal Power (RTP) within 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months or verification every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of the quadrant power tilt ratio (QPTR) within limit using the movable in-core detectors.

The NRC staff notes that while there is no requirement of reducing thermal power to 75 precent RTP within 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months or verification every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of the QPTR within limit using the movable in-core detectors, the QPTR is addressed in TS 3.2.4 where Required Action A.1 requires reduction of thermal power by 3 percent from RTP for each 1 percent of QPTR > 1.00 and Required Action A.2 requires determination of QPTR every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Since the power range neutron flux high trip function has two-out-of-four trip logic, in the case of one of the channels failing (while one other channel is inoperable) the NRC staff finds that there is sufficient redundancy to implement the trip function if needed during the extended period allowed by the RICT.

Based on TS 3.2.4 and sufficient redundancy to perform the function, the NRC staff finds the proposed variation to TS 3.3.1 Condition D for the power range neutron flux high function to be acceptable and concludes that the plant will maintain adequate DID.

TS 3.3.1 Condition L - Reactor Coolant Flow - Low, Single Loop & Condition K - Reactor Coolant Flow - Low, Two Loops TS 3.3.1, Conditions K and L, require the reactor coolant flow low channel to be placed in tripped position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of inoperability when above the P-8 interlock setpoint (Condition L) and when below the P-8 interlock setpoint and above the P-7 interlock setpoint (Condition K).

Conditions K and L differ from the Westinghouse STS in TSTF-505, Revision 2, which specifies a single functional unit for the reactor coolant flow low trip instrumentation without distinction of one versus two affected reactor coolant system (RCS) loops, thus requiring power reduction below the P-7 interlock setpoint. Tripping one reactor coolant flow low channel while above the P-8 interlock setpoint results in a partial trip condition requiring only one additional channel in the same RCS loop to initiate a reactor trip.

Similarly, tripping one RCS flow low channel in each of the RCS loops results in a partial trip condition requiring one additional channel in both RCS loops to initiate a reactor trip when between P-7 and P-8 interlock setpoints. Sufficient redundancy exists in the RCS flow low circuitry to ensure at least two channels are available to implement the RCS flow low trip function if needed during the extended period allowed by the RICT.

Since sufficient redundancy exists in the RCS flow low channels to ensure at least two channels are available to implement the RCS flow low trip function during the extended period allowed by the RICT program, the NRC staff finds the proposed variation to TS 3.3.1 Conditions K and L for the reactor coolant flow low function to be acceptable and concludes that the plant will maintain adequate DID.

TS 3.3.1 Condition Q - Reactor Trip Breakers TS 3.3.1, Condition Q, requires restoration of an inoperable reactor trip breaker (RTB) to operable status in modes 1 and 2 which corresponds to the Westinghouse STS 3.3.1, Condition U, which requires restoration of an inoperable RTB train to operable status in Modes 1 and 2. The NRC staff finds that since an inoperable RTB renders the RTB train inoperable, the two conditions are functionally equivalent. Because the variation is functionally identical with regards to its application, the NRC staff finds the proposed variation to TS 3.3.1, Condition Q, for the RTBs to be acceptable and concludes that the plant will maintain adequate DID.

TS 3.3.2 Condition G and Condition M - Feedwater Isolation Automatic Actuation Logic and Actuation Relays TS 3.3.2, Condition G, requires restoration of one inoperable Feedwater Isolation Automatic Logic and Actuation Relay train within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in mode 3 in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and mode 4 in 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months , if the CT is not met. The proposed change relocates the Required Actions to be in Mode 3 and mode 4 into Condition M which requires the plant to be in Mode 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Mode 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , if Condition G CT is not met. Conditions G and M correspond to the Westinghouse STS in TSTF-505, Revision 2 Conditions H and O which specify restoration of one inoperable train within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and require the plant to be in Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months if Condition H CT is not met.

The required action for proposed Condition G requires restoration of one inoperable train within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months versus the corresponding TSTF-505, Revision 2, Condition H, which requires completion within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The NRC staff finds that because the CT is consistent with the current TS and is less than that in TSTF-505, Revision 2, the proposed Condition G variation is conservative and therefore acceptable. The required action for proposed Condition M, requires entry into Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Mode 4 in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months versus the corresponding TSTF-505, Revision 2, Condition O, which requires entry into Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The variation of an additional end state, Mode 4, is appropriate since it is consistent with the current TS and entry into Mode 4 no longer requires these functions to be operable since the mode of applicability is

Modes 1, 2 and 3. Sufficient redundancy exists to ensure feedwater isolation can be initiated by either train for automatic actuation logic and actuation relays. Additionally, Westinghouse STS in TSTF-505, Revision 2 specifies a turbine trip function with actuation of feedwater isolation, where the current Point Beach feedwater isolation signals do not initiate a turbine trip. This variation is specific to the Point Beach design basis which uses the non-safety related anticipated transient without scram (ATWS) Mitigation System Actuation Circuitry (AMSAC) function to trip the turbine in the event of a total loss of main feedwater without reactor or turbine trip and does not impact the application of TSTF-505, Revision 2. Therefore, the NRC staff finds the proposed variation to TS 3.3.2 Conditions G and M for the feedwater isolation automatic actuation logic and actuation relays to be acceptable and concludes that the plant will maintain adequate DID.

TS 3.3.2 Condition D and Condition M - Feedwater Isolation Steam Generator (SG) Water Level - High TS 3.3.2, Condition D, requires one inoperable Feedwater Isolation SG Water Level - High channel to be placed in trip within one hour or be in Mode 3 in 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months and Mode 4 in 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months , if the CT is not met. The proposed change relocates the Required Actions to be in Mode 3 and Mode 4 into Condition M which requires the plant to be in Mode 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Mode 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , if Condition D CT not met. Conditions D and M correspond to Westinghouse STS in TSTF-505, Revision 2, Conditions I and O which specify one inoperable channel to be placed in trip within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and require the plant to be in Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , if Condition I CT is not met.

The required action for proposed Condition D requires one inoperable channel to be placed in trip within one hour versus the corresponding TSTF-505, Revision 2, Condition I, which requires completion within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The NRC staff finds that because the completion time is consistent with the current TS and is less than TSTF-505, Revision 2, the proposed Condition D variation is conservative and therefore acceptable. The required action for proposed Condition M, requires entry into Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Mode 4 in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months versus the corresponding TSTF-505, Revision 2, Condition O, that requires entry into Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The variation in the additional end state, Mode 4, is appropriate since it is consistent with the current TS and entry into Mode 4 would no longer require these functions to be operable since the mode of applicability is 1, 2 and 3. Sufficient redundancy exists to ensure feedwater isolation can be initiated given the two-out-of-three logic on SG Water Level - High. Additionally, Westinghouse STS in TSTF-505, Revision 2 specifies a turbine trip function with actuation of feedwater isolation, where the current Point Beach feedwater isolation signals do not initiate a turbine trip.

This variation is specific to the Point Beach design basis which uses the non-safety related ATWS AMSAC function to trip the turbine in the event of a total loss of main feedwater without reactor or turbine trip and does not impact the application of TSTF-505, Revision 2. Therefore, the NRC staff finds the proposed variation to TS 3.3.2, Conditions D and M, for the Feedwater Isolation SG Water Level - High to be acceptable and concludes that the plant will maintain adequate DID.

TS 3.7.2 Condition A - Main Steam Isolation Valves and Non-Return Check Valves TS 3.7.2, Condition A, addresses one SG flow path with one or more inoperable main steam isolation valves (MSIV) or non-return check valves. Further, with both the MSIV and the non-return check valve of the same SG flow path inoperable, a non-faulted steam line cannot be isolated from a main steam line break outside containment, which constitutes a LOF. To prevent application of a RICT to a LOF condition, the licensee proposes a note to TS 3.7.2 Condition A

CT which limits the application of the RICT to either one inoperable MSIV or one inoperable non-check valve, but not both, in an SG flow path. The proposed note is consistent with the NRC model SE which states that the addition of a note to Required Actions is an acceptable method for limiting the application of RICTs to a LOF condition. TS 3.7.2, Condition A, differs from the Westinghouse STS in TSTF-505, Revision 2, as the latter does not specify requirements for the non-return check valves. The NRC staff finds the proposed variation in TS 3.7.2, Condition A, CT is consistent with the NRCs revised model SE to limit application of the RICT to only either the MSIV or non-check return valve in a steam flow path thus preventing LOF.

Because the RICT Program will not be applied to a LOF, the NRC staff concludes that the proposed variation in TS 3.7.2, Condition A, is acceptable and concludes that the plant will maintain adequate DID.

TS 3.7.7 - Conditions A, Component Cooling Pumps & Condition B, Component Cooling Heat Exchangers TS 3.7.7, Conditions A and B, address the condition of an inoperable component cooling (CC) pump and an inoperable CC heat exchanger, respectively. TS 3.7.7, Conditions A and B, differ from the Westinghouse STS in TSTF-505, Revision 2, which addresses in one condition an inoperable CC train. There is sufficient redundancy within each CC loop to provide 100 percent of the required cooling capacity during normal operations and post-accident conditions using the associated standby CC pumps and heat exchangers if a single CC pump or CC heat exchanger remains inoperable. The CC system has sufficient component level redundancy to ensure required peak cooling capacity under all plant conditions.

The NRC staff finds that there is sufficient redundancy to ensure cooling capacity during normal and accident conditions. The CC loops of each unit operate independently with two CC pumps and one CC heat exchanger being available for use, while the two CC heat exchangers serve as shared standby units. The remaining pumps and heat exchangers are used to provide CC to auxiliary and containment buildings or are in standby mode. Based on the available redundancy to provide sufficient CC during normal and accident conditions, the NRC staff finds the variations in TS 3.7.7, Conditions A and B, are acceptable and concludes that the plant will maintain adequate DID.

TS 3.7.8 - Conditions A, C, and D Service Water System TS 3.7.8, Condition A, addresses the condition of one inoperable service water (SW) pump with both units in Modes 1, 2, 3 or 4. TS 3.7.8, Condition A, differs from the Westinghouse STS in TSTF-505, Revision 2, which specifies requirements for an inoperable SW train. The loss of a SW pump does not render the SW system incapable of performing its required function during normal operating or DBA conditions, as all six SW pumps feed into a continuous discharge ring header that effectively results in two SW flow paths directing flow to both trains of all loads for both units. This means with one inoperable SW pump, failure of a safeguards train supporting the start signal for three of the operable SW pumps would leave two remaining operable SW pumps providing sufficient heat sink for the safety related components on both units.

The NRC staff finds that sufficient redundancy is available with six pumps powered by four different safeguard buses on two units feeding into a continuous discharge ring header that results in two SW flow paths directing flow to both trains of all loads for both units. Based on

sufficient redundancy being available, the NRC staff finds the proposed variation in TS 3.7.8, Condition A, to be acceptable and concludes that the plant will maintain adequate DID.

TS 3.7.8, Condition C, addresses the interruption of the SW ring header continuous flow path and differs from the Westinghouse STS in TSTF-505, Revision 2, which specifies requirements for an inoperable SW train in Condition A. By employing system manual and automatic valves, during plant operation the ring header continuous flow path can be interrupted for maintenance purposes during which all SW loads are supplied from either the north or south SW header without losing redundancy provided the ring header is intact in both directions around the ring.

Further, in attachment 5 to the LAR, the licensee states that isolation of any SW header will not impact the ability of the SW system to supply cooling water to the required number of essential loads on either unit.

The NRC staff finds that redundancy is available for the SW ring header continuous flow path which can be interrupted for maintenance purposes during which all SW loads are supplied, and the isolation of any SW header will not impair the ability of the SW system to supply cooling water to the essential loads on either unit. Based on sufficient redundancy being available, the NRC staff finds the proposed variation in TS 3.7.8, Condition C, to be acceptable and concludes that the plant will maintain adequate DID.

TS 3.7.8, Condition D, addresses one or more non-essential SW load flow paths with one required automatic isolation valve inoperable and the affected non-essential flow paths not isolated. TS 3.7.8, Condition D, differs from the Westinghouse STS in TSTF-505, Revision 2, which specifies the requirements for an inoperable SW train in Condition A. The non-essential loads are supplied by five branches that connect to the SW ring header accompanied by redundant isolation valves that close upon receiving a safety injection signal from either of the units. Thus, the condition of multiple non-essential SW load flow paths, where each has one required automatic valve inoperable, would not necessitate additional operating SW pumps during plant operations or DBA conditions.

The NRC staff finds that the SW system capacity is unaffected by single inoperable isolation valve(s) associated with a non-essential SW flow path during an extended period of inoperability based on the supply of non-essential loads by five branches connected to the SW ring header accompanied by redundant isolation valves. Based on the discussion provided above, the NRC staff finds the proposed variation in TS 3.7.8, Condition D, to be acceptable and concludes that the plant will maintain adequate DID.

3.2.2.1 Key Principle 2: Evaluation of Defense-in-Depth Conclusions The NRC staff notes that while in a TS LCO condition, the redundancy of the affected system will be temporarily relaxed and, consequently, the system reliability is degraded accordingly.

The NRC staff examined the design information from the Point Beach UFSAR and the risk informed TS LCO conditions for the affected safety functions. Based on this information, the NRC staff confirmed that under any given DBA evaluated in the Point Beach UFSAR, the affected protective features maintain adequate DID.

Considering that the CT extensions will be implemented in accordance with the NEI 06-09-A guidance, which also considers RMAs, and the redundancy of the offsite and onsite power systems, the NRC staff finds that the plant will maintain adequate DID. Therefore, the NRC staff finds the TS LCOs proposed by the licensee in attachment 2 to the LAR, as supplemented are acceptable for the RICT Program.

The NRC staff reviewed all TS LCOs proposed by the licensee in attachment 2 to the LAR, as supplemented, and concludes that the proposed changes do not alter the ways in which the Point Beach systems fail, do not introduce new CCF modes, and the system independence is maintained.

The NRC staff finds that some proposed changes reduce the level of redundancy of the affected systems, and this reduction may reduce the level of defense against some CCFs; however, such reductions in redundancy and defense against CCFs are acceptable due to existing diverse means available to maintain adequate DID against a potential single failure during a RICT. The NRC staff finds that extending the selected CTs with the RICT Program following loss of redundancy, but maintaining the capability of the system to perform its safety function, is an acceptable reduction in DID during the proposed RICT period provided that the licensee identifies and implements compensatory measures in accordance with the RICT Program during the extended CT.

Based on the above, the NRC staff concludes that the licensees proposed changes are consistent with the NRC endorsed guidance prescribed in NEI 06-09-A, along with TSTF-439, Revision 2, and satisfy the second key principle in RG 1.174 and RG 1.177. Additionally, the NRC staff concludes that the changes are consistent with the DID philosophy as described in RG 1.174 and that the removal of the second CTs remain consistent with the DID philosophy.

3.2.3 Key Principle 3: Evaluation of Safety Margins Paragraph 50.55a(h) of 10 CFR Part 50 requires, in part, that [p]rotection systems of nuclear power reactors of all types must meet the requirements specified in this paragraph.

Section 2.2.2, Technical Specification Change Maintains Sufficient Safety Margin (Principle 3),

of RG 1.177 states, in part, that sufficient safety margins are maintained when:

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

Safety analysis acceptance criteria in the final safety analysis report are met, or proposed revisions provide sufficient margin to account for analysis and data uncertainties....

The licensee is not proposing in this application to change any quality standard, material, or operating specification. In the LAR, as supplemented the licensee proposed to add the RICT Program in section 5.0, Administrative Controls, of the TSs, which requires adherence to NEI 06-09-A. Furthermore, the licensee proposed to remove second CTs for the specified TS provided in the LAR, as supplemented.

The NRC staff evaluated the effect on safety margins when the RICT is applied to extend the CT up to a backstop of 30 days in a TS condition with sufficient trains remaining operable to fulfill the TS safety function. Although the licensee will be able to have design-basis equipment out of service longer than the current TS allow, any increase in unavailability is expected to be insignificant and is addressed by the consideration of the single failure criterion in the design basis analyses. Acceptance criteria for operability of equipment are not changed and, if sufficient trains remain operable to fulfill the TS safety function, the operability of the remaining train(s) ensure(s) that the current safety margins are maintained. The NRC staff finds that if the specified TS safety function remains operable, sufficient safety margins would be maintained during the extended CT of the RICT Program.

Safety margins are also maintained if PRA functionality is determined for the inoperable train, which would result in an increased CT. Credit for PRA functionality, as described in NEI 06-09-A, is limited to the inoperable train, subsystem, or component.

Based on the above, the NRC staff finds that the design basis analyses for Point Beach remain applicable and unchanged, sufficient safety margins would be maintained during the extended CT, and the proposed changes to the TSs do not include any change in the standards applied or the safety analysis acceptance criteria. The NRC staff concludes that the proposed changes meet 10 CFR 50.55a(h), and therefore, the third key principle in RG 1.174 is satisfied.

3.2.4 Key Principle 4: Change in Risk Consistent with the Safety Goal Policy Statement NEI 06-09-A provides a methodology for a licensee to evaluate and manage the risk impact of extensions to TS CTs. Permanent changes to the fixed TS CTs are typically evaluated by using the three-tiered approach described in Section 16.1 of NUREG-0800, and RG 1.177. This approach addresses the calculated change in risk as measured by the change in core damage frequency (CDF) and large early release frequency (LERF), as well as the incremental conditional core damage probability and incremental conditional large early release probability; the use of compensatory measures to reduce risk; and the implementation of a configuration risk management program (CRMP) to identify risk significant plant configurations.

The NRC staff evaluated the licensees processes and methodologies for determining that the change in risk from implementation of RICTs will be small and consistent with the intent of the Commissions Safety Goals Policy Statement. In addition, the NRC staff evaluated the licensees proposed changes against the three-tiered approach in RG 1.177 for the licensees evaluation of the risk associated with a proposed TS CT change. The results of the NRC staffs review are discussed below.

3.2.4.1 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed changes on plant operational risk. The Tier 1 review involves two aspects: (1) scope and acceptability of the PRA models and their application to the proposed changes, and (2) a review of the PRA results and insights described in the licensees application.

Enclosures 2, Information Supporting PRA Consistency with RG 1.200, (Reference 28) and 4, Information Supporting Justification of Excluding Sources of Risk not Addressed by PRA Models, (Reference 34) to the LAR, as supplemented, identified the following modeled hazards and alternate methodologies the licensee proposed to be used in the Point Beach RICT Program to assess the risk contribution for extending the CT of a TS LCO.

Internal Events Probabilistic Risk Assessment (IEPRA) model (includes internal floods)

Internal Fire Events Probabilistic Risk Assessment (FPRA) model Seismic Hazard: CDF penalty of 6.2E-6 per year, and a LERF penalty of 2.8E-6 per year

Other External Hazards: screened out from RICT Program based on Appendix 6-A of the American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) RA-Sa-2009 PRA Standard, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications (Reference 35)

Evaluation of IEPRA and FPRA Models The IEPRA and FPRA models supporting the RICT Program are discussed in enclosure 2 to the LAR, as supplemented. The licensee stated that the PRA models have been peer reviewed using the ASME/ANS RA Sa 2009 PRA Standard for the IEPRA and FPRA and RG 1.200, Revision 2. Additionally, the licensee stated that the PRA models have been peer reviewed to the requirements of NEI 05-04, Revision 2, Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard, (Reference 36) and NEI 07-12, Revision 1, Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines, (Reference 37). For the open facts and observations (F&Os) resulting from these peer reviews, the licensee stated that closure of the F&Os was performed using an independent assessment process. The NRC staff confirmed that the licensee performed closure of the F&Os consistent with Appendix X to NEI 05-04, NEI 07-12, and NEI 12-13, as endorsed in RG 1.200. The NRC evaluated the remaining open F&O, along with its disposition.

In enclosure 9, Key Assumptions and Sources of Uncertainty, (Reference 38) to the LAR, the licensee provided a discussion and list of the potential key assumptions and sources of uncertainty, along with treatment for the application of TSTF-505. In enclosure 2 to the LAR, the licensee stated that no portable FLEX mitigating strategies are incorporated into the Point Beach PRA models used in this LAR.

The NRC staff reviewed the PRA models peer review history provided by the licensee in enclosure 2 to the LAR, as supplemented. The licensee adequately applied the guidance for establishing PRA technical acceptability for the IEPRA and FPRA models. The NRC staff further considered the potential key assumptions and key sources of uncertainty identified by the licensee, and the proposed use of surrogates in the PRA models for specific TS functions.

Therefore, the NRC staff finds the Point Beach IEPRA and FPRA models to be acceptable commensurate with the RICT application because the licensees use of the PRA models in the integrated decision-making process is consistent with RG 1.174, Revision 3.

Evaluation of Seismic Hazard The licensees approach for including the seismic risk contribution in the RICT calculation is to add a penalty seismic CDF and a penalty seismic LERF to each RICT calculation. The proposed bounding seismic CDF estimate is based on using the plant-specific seismic hazard curves developed in response to the Near-Term Task Force recommendation 2.1 (Reference 39), and a plant-level high confidence of low probability of failure (HCLPF) capacity of 0.16g referenced to peak ground acceleration (PGA). The uncertainty parameter for seismic capacity was represented by a composite beta factor of 0.45. The calculated seismic CDF penalty is 6.2E-6 per year. The staff finds that the method to determine the baseline seismic CDF acceptable because it is consistent with the approach used in Generic Issue (GI)-199, Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants (Reference 40). The NRC staff used the input parameters identified by the licensee to confirm the proposed bounding seismic CDF estimate.

Concerning the proposed bounding seismic LERF estimate, the licensee explains in the LAR supplement that an estimate of the seismic LERF is obtained by using the estimated seismic CDF (as described above) with a limiting fragility for containment integrity, also assumed to be 0.16g PGA HCLPF. The calculated seismic LERF is 2.8E-6 per year. The NRC staff finds that the licensees approach to determine a seismic LERF estimate to be acceptable because use of a 0.16g PGA HCLPF as the limiting fragility for containment integrity is conservative.

The licensee addressed the incremental risk associated with seismic-induced loss of offsite power (LOOP) in its supplement. A seismic LOOP frequency across the entire hazard interval is 1.6E-5 per year. This is about 1 percent of the total internal events 24-hour non-recovered LOOP frequency of 1.6E-3 per year already addressed in the IEPRA. The NRC staff evaluated the licensees analysis and finds it adequately addresses the impact of seismically induced LOOP on risk and that its exclusion from the non-recovered LOOP frequency has an insignificant impact on the RICT program calculations.

The NRC staff finds that, during RICTs for SSCs credited in the design basis to mitigate seismic events, the licensee's proposed methodology captures the risk associated with seismically induced failures of redundant SSCs because such SSCs are assumed to be fully correlated. In summary, the NRC staff finds the licensees proposal to use the seismic CDF contributions of 6.2E-6 per year, and a seismic LERF contribution of 2.8E-6 per year to be acceptable for the licensees RICT Program for Point Beach, because (1) the licensee used the most current site-specific seismic hazard information for Point Beach, (2) the licensee used an acceptably low plant level HCLPF value of 0.16g and a combined beta factor of 0.45 consistent with the information for Point Beach in the GI-199 evaluation, (3) the licensee determined a seismic LERF penalty based on its estimate of seismic CDF combined with using a containment integrity fragility of 0.16g PGA HCLPF, and (4) adding baseline seismic risk to RICT calculations, which assumes the fully correlated failures, is conservative for SSCs credited in seismic events, while any potential for non-conservative results for SSCs that are not credited in seismic events is small or nonexistent.

Evaluation of Other External Hazards Besides seismic, the licensee confirmed that other external hazards for Point Beach have insignificant contribution and proposed these hazards be screened out from the RICT program.

For external floods, the licensees conclusions regarding insignificant risk contribution were based on the flood hazard reevaluation report (FHRR) (Reference 41) and Flooding Focused Evaluation report for Point Beach (Reference 42). The NRC staffs assessment of flooding focused evaluation (Reference 43) concluded that the licensee demonstrated a feasible response to the reevaluated local intense precipitation (LIP) flood hazard. For high winds, the licensee stated in section 2.1 of enclosure 4 to the LAR that the hazard can be screened out based on the Point Beach individual plant examination of external events (IPEEE, (Reference 44)) evaluation of a CDF of 3.4E-7 per year for high winds hazard. With significant plant modifications after the IPEEE evaluation, its current risk level should be lower than the IPEEEs CDF. The licensee provided its assessment of other external hazard risk for the RICT Program in LAR enclosure 4. The hazards assessed in LAR are those identified for consideration in non-mandatory Appendix 6-A of the ASME/ANS PRA Standard and provides a guide for identification of most of the possible external events for a plant site.

The NRC staff considered that certain plant configurations under external hazards could place the plant at a high risk and the hazards may not be screened. In its supplement (Reference 3),

the licensee explained that the external hazard screening evaluation considered potentially

adverse plant configurations and the evaluation still allowed the external hazards to be screened. Based on the inclusion of plant configurations in the external hazard screening, the NRC staff finds the Point Beach approach to external hazard screening to be adequate for this application.

The NRC staff reviewed the information in the submittal and supplements, and finds that the contributions from external flooding, high winds, and other external hazards have an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs because they either do not challenge the plant or they are bounded by the external hazards analyzed for the plant. For all other external hazards, the NRC staff notes that the preliminary screening criteria and progressive screening criteria used and presented in LAR table E4-2 is the same criteria presented in supporting requirements for screening external hazards EXT-B1, EXT-B2, and EXT-C1 of the ASME/ANS PRA Standard.

Application of PRA Models, Results, and Insights in the RICT Program The Point Beach base PRA models that have been determined to be acceptable in this SE will be modified as an application specific PRA model (i.e., CRMP tool), that will be used to analyze the risk for an extended CT. The CRMP model produces results (i.e., risk metrics) that are consistent with the NEI 06-09-A guidance. The LAR, as supplemented, provided all information needed to support the requested LCO actions proposed for the Point Beach RICT Program consistent with the limitations and conditions detailed in section 4.0 of the NRCs final SE incorporated in NEI 06-09-A.

The NRC staff did not identify any insufficiencies in the licensees information or the CRMP tool as described in the enclosure 8, Attributes of the Configuration Risk Management Model, (Reference 38) to the LAR. Furthermore, as stated in attachment 1 to the LAR, the proposed changes do not change the design, configuration, or method of operation of the plant. The proposed changes do not involve a physical alteration of the plant (no new or different kind of equipment will be installed). The NRC staff finds that the Point Beach PRA models and CRMP tool used will continue to reflect the as built, as operated plant, consistent with RG 1.200, for ensuring PRA acceptability is maintained. Therefore, the NRC staff concludes that the proposed application of the Point Beach RICT Program is appropriate for use in the adoption of TSTF-505 for performing RICT calculations.

The licensee provided in enclosure 5, Total Plant (Baseline) CDF and LERF, (Reference 34) to the LAR, as supplemented, the estimated total CDF and LERF of the base PRA models to demonstrate that Point Beach meets the 1E-4/year CDF and 1E-5/year LERF criteria of RG 1.174, consistent with the guidance in NEI 06-09-A, and that these guidelines will be satisfied for implementation of a RICT.

The licensee has incorporated NEI 06-09-A into TS 5.5.7. The estimated current total CDF and LERF for Point Beach PRAs meet the RG 1.174 guidelines, therefore, the NRC staff concludes the PRA results and insights used by the licensee in the RICT Program will continue to be consistent with NEI 06-09-A.

3.2.4.1.1 Tier 1 Conclusions Based on the above, the NRC staff finds that the licensee has satisfied the intent of Tier 1 in RG 1.177, for determining the acceptability of the PRA, including the scope of the PRA models

(i.e., IEPRA and FPRA), the evaluation of external hazards such as seismic and other external hazards are appropriate for this application.

3.2.4.2 Tier 2: Avoidance of Risk-Significant Plant Configurations As detailed in RG 1.177, the second tier evaluates the capability of the licensee to identify and avoid risk significant plant configurations that could result if equipment, in addition to that associated with the proposed change, is taken out of service simultaneously or if other risk significant operational factors, such as concurrent system or equipment testing, are also involved. In section 3.1, Description of Monitoring Program, of enclosure 11, Monitoring Program, (Reference 33) to the LAR the licensee confirmed that the risk thresholds associated with 10 CFR 50.65(a)(4) will be coordinated with the RICT limits. Enclosure 12 to the LAR identifies three kinds of RMAs (i.e., actions to provide increased risk awareness and control, actions to reduce the duration of maintenance activities, and actions to minimize the magnitude of the risk increase). The LAR also explains that RMAs will be implemented in accordance with current plant procedures and no later than the time at which the 1E-6 incremental core damage probability (ICCDP) or 1E-7 incremental large early release probability (ICLERP) threshold is reached and under emergent conditions when the instantaneous CDF and LERF thresholds are exceeded.

The NRC staff concludes that the Tier 2 attributes of the proposed RICT Program, including limits established for entry into a RICT and implementation of RMAs, are consistent with the guidance in NEI 06-09-A. Therefore, the proposed changes are consistent with the intent of Tier 2 in RG 1.177.

3.2.4.3 Tier 3: Risk--Informed Configuration Risk Management The third tier stipulates that a licensee should develop a program that ensures the risk impact of out of service equipment is appropriately evaluated prior to performing any maintenance activity.

The proposed RICT Program establishes a CRMP based on the underlying PRA models. The CRMP is then used to evaluate configuration specific risk for planned activities associated with the RMTS extended CT, as well as emergent conditions which may arise during an extended CT. This required assessment of configuration risk, along with the implementation of compensatory measures and RMAs, is consistent with the principle of Tier 3 for assessing and managing the risk impact of out of service equipment.

Paragraph 50.36(c)(5) of 10 CFR identifies administrative controls as the provisions relating to organization and management, procedures, [thereby] assuring operation of the facility in a safe manner. In enclosure 8 to the LAR, the licensee confirmed that future changes made to the baseline PRA models and changes made to the online model (i.e., CRMP) are controlled and documented by NextEra Energy fleet procedures. Enclosure 10, Program Implementation, (Reference 38) to the LAR, provided the attributes that the licensees RICT Program procedures will address, which are consistent with NEI 06-09-A. The NRC staff finds that the licensee has identified appropriate administrative controls consistent with NEI 06-09-A and 10 CFR 50.36(c)(5).

Based on the licensees incorporation of NEI 06-09-A in the TSs (discussed in LAR attachment 2, as supplemented) and its use of RMAs (discussed in LAR enclosure 12), and because the proposed changes are consistent with the Tier 3 guidance of RG 1.177, the NRC

staff finds the licensees Tier 3 program is acceptable and supports the proposed implementation of the RICT Program.

3.2.4.4 Key Principle 4: Conclusions The licensee has demonstrated the technical acceptability and scope of its PRA models and alternative methods for considering the impact of seismic events, high winds and other external hazards, and that the models can support implementation of the RICT Program for determining extensions to CTs. The licensee has made proper consideration of the key assumptions and sources of uncertainty. The risk metrics are consistent with the approved methodology of NEI 06-09-A and the acceptance guidance in RG 1.174 and RG 1.177. The RICT Program will be controlled administratively through plant procedures and training and follows the NRC approved methodology in NEI 06-09-A. The NRC staff concludes that the RICT Program satisfies the fourth key principle of RG 1.174 and RG 1.177, and therefore, is acceptable.

3.2.5 Key Principle 5: Performance Measurement Strategies - Implementation and Monitoring RG 1.174 and RG 1.177 establish the need for an implementation and monitoring program to ensure that extensions to TS CTs do not degrade operational safety over time and that no adverse degradation occurs due to unanticipated degradation or common cause mechanisms. 1 to the LAR states, that the SSCs in the scope of the RICT Program are also in the scope of 10 CFR 50.65 for the Maintenance Rule. The Maintenance Rule monitoring programs will provide for evaluation and disposition of unavailability impacts which may be incurred from implementation of the RICT Program. Furthermore, in enclosure 11 to the LAR, the licensee confirmed that the cumulative risk is calculated at least every refueling cycle, but the recalculation period does not exceed 24 months, which is consistent with NEI 06-09-A.

The NRC staff concludes that the RICT Program satisfies the fifth key principle of RG 1.174 and RG 1.177 because: (1) the RICT Program will monitor the average annual cumulative risk increase as described in NEI 06-09-A, thereby, ensuring the program, as implemented, continues to meet the guidance in RG 1.174 for small risk increases; and (2) all affected SSCs are within the Maintenance Rule program, which is used to monitor changes to the reliability and availability of these SSCs.

For the removal of the second CTs, there are two existing programs that provide a strong disincentive to licensees continuing operation with alternating Required Actions. These programs are the monitoring report (10 CFR 50.65) program and the ROP.

The TS CT for one system within an LCO is not generally affected by inoperable equipment in another LCO. However, the second CT influences the CT for one system based on the condition of another system, but only if the two systems are required by the same LCO.

Paragraph 50.65(a)(4) of 10 CFR is a much better mechanism to apply this influence, as the monitoring report considers all inoperable risk-significant equipment, not just the one or two systems governed by the same LCO. Furthermore, as discussed above, the monitoring report requires each licensee to monitor the performance or condition of SSCs against licensee-established goals to ensure the SSCs are capable of fulfilling their intended functions.

The performance and condition monitoring activities required by 10 CFR 50.65 identify maintenance practices that would result from multiple entries into the actions of the TSs and unacceptable unavailability of these SSCs. The effectiveness of these performance monitoring activities, and associated corrective actions is evaluated at least every refueling cycle, not to exceed 24 months per 10 CFR 50.65.

In addition to the monitoring report, the reporting of performance indicator data governed by NEI 99-02, Regulatory Assessment Performance Indicator Guideline (Reference 45), as endorsed by RIS 2001-11, Voluntary Submission of Performance Indicator Data (Reference 46), establishes an acceptable method for the submission of performance indicator data to the NRC. The ROP consists of cornerstones that include inspection of the indicators to ensure all ROP objectives are being met. The mitigating systems cornerstone specifically addresses the AC sources-operating which encompasses the AC sources and distribution system LCOs and the auxiliary feedwater system. Any extended unavailability of these systems due to multiple entries into the TS Actions would affect the NRCs evaluation of the licensees performance indicator data provided under the ROP. The licensees performance within the mitigating systems ROP cornerstone provides reasonable assurance in monitoring the inappropriate use of TS condition CTs.

In addition to these regulatory programs, NextEra Fleet administrative procedures prohibit the application of LCO Conditions in a manner which extend indefinitely periods of failing to satisfy an LCO, which is consistent with the administrative controls recommended in TSTF-439, Revision 2. Specifically, NextEra Fleet Administrative procedure OP-AA-100-1000, Conduct of Operations, states:

It may be possible to alternate between Actions in such a manner that operation could continue indefinitely without satisfying an LCO. Doing so, however, would be inconsistent with the basis for the Allowed Outage Time, and is NOT allowed (AR 2007220)

The NRC staff concludes that the licensee continues to have mechanisms in place to monitor and to limit the maximum time allowed for any combination of conditions that could result in a single contiguous occurrence of failing to meet the LCO. The NRC staff finds the proposed deletion of second CTs are acceptable because multiple, continuous entries into TSs conditions, without meeting the LCO, will be adequately controlled by: (1) the licensees administrative controls, (2) the CRMPs as implemented to meet the requirements of the monitoring report to assess and manage risk and performance indicators, and (3) assessment of the licensees performance within the mitigating systems ROP cornerstone. In addition, the NRC staff finds the monitoring report provides adequate assurance against inappropriate use of combinations of TS conditions that result in a single contiguous occurrence of failing to meet the LCO. Accordingly, consistent with TSTF-439, Revision 2, the NRC staff finds the proposed changes to be acceptable.

3.3 Variations The licensee proposed variations in TSs 3.3.1, 3.3.2, 3.6.3, 3.7.2, 3.7.7 and 3.7.8 from the Westinghouse STS in TSTF-505, Revision 2. Based on the above review, the NRC staff concludes that the TSs, as amended by the proposed changes, will continue to meet the requirements of 50.36(c)(2) because the LCOs will continue to state the lowest functional capability or performance levels of equipment required for safe operation of the facility. The NRC staff concludes that the remedial actions, as amended by the proposed change, provide reasonable assurance that facility operation remains safe during the time the LCOs are not met.

Therefore, the proposed changes to the TSs are acceptable.

3.4 Technical Evaluation Conclusion

The NRC staff has evaluated the proposed changes against each of the five key principles in RG 1.174 and RG 1.177, including the proposed variations from the approved TSTF-505, Revision 2, discussed in sections 3.2 and 3.3 of this SE. The NRC staff concludes that the changes proposed by the licensee satisfy the key principles of risk informed decision-making identified in RG 1.174 and RG 1.177, and, therefore, the requested adoption of the proposed changes to the TSs and associated guidance, is acceptable to assure the paragraphs of 10 CFR Part 50 identified in section 2.0 of this SE continue to be met.

4.0 STATE CONSULTATION

In accordance with the Commissions regulations, on April 12, 2023, the Wisconsin State official was notified of the proposed issuance of the amendments. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

These amendments change a requirement with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR part 20 or change a surveillance requirement. The NRC staff has determined that the amendments involve no significant increase in the amounts and no significant change in the types of any effluent that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously published a proposed finding in the Federal Register on August 9, 2022 (87 FR 48517) that these amendments involve no significant hazards consideration and there has been no public comment on such finding.

Accordingly, these amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of these amendments.

6.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

7.0 REFERENCES

1 Strope, M., NextEra Energy Point Beach, LLC, letter to U.S. Nuclear Regulatory Commission, "License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b'," dated May 20, 2022, (ML22140A131).

2 Strand, D., NextEra Energy Point Beach, LLC, letter to U.S. Nuclear Regulatory Commission, "Response to Request for Supplemental Information Regarding License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times - RITSF Initiative 4b," dated July 11, 2022, (ML22192A152).

3 Strand, D., NextEra Energy Point Beach, LLC, letter to U.S. Nuclear Regulatory Commission, "Response to Requests for Additional Information Regarding License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times-RITSTF Initiative 4b'," dated January 11, 2023, (ML23011A280).

4 Strand, D., NextEra Energy Point Beach, LLC, letter to U.S. Nuclear Regulatory Commission, "Response to Requests for Additional Information Regarding License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Cmpletion Times TSTF-505, Revision 2, "Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b," dated February 21, 2023 (ML23052A112).

5 U.S. Nuclear Regulatory Commission, "TSTF-505, Revision 2, TSTF Comments on Draft Safety Evaluation for Traveler TSTF-505, Provide Risk-Informed Extended Completion Times and Submittal of TSTF-505, Revision 2," dated July 2, 2018 (ML18183A493).

6 U.S. Nuclear Regulatory Commission, "Final Revised Model Safety Evaluation of Traveler TSTF-505, Revision 2, Provide Risk Informed Extended Completion Times - RITSTF Initiative 4B," TSTF-505, Revision 2, dated November 21, 2018 (ML18269A041).

7 Strope, M., NextEra Energy Point Beach, LLC, Attachement 1 of letter 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 Completions Times - RITSTF Initiative 4b'," dated May 20, 2022, (ML22140A133).

8 Wall, S. P., U.S. Nuclear Regulatory Commission, letter to Coffey, B. Florida Power &

Light Company, "Point Beach Nuclear Plant, Units 1 and 2 - Audit Summary for License Amendment Request to Adopt Risk-Informed Extended Completion Times - Risk Informed Technical Specifications Task Force Initiative 4B (EPID L-20022-LLA-0074)," dated February 21, 2023 (ML23039A002).

9 Wall, S., U.S. Nuclear Regulatory Commission email correspondence to Schultz, E.,

NextEra Energy Point Beach, LLC, "Final RAI - Point Beach 1 & 2 - License Amendment Request Regarding TSTS-505 (EPID No. L-2022-LLA-0074)," dated December 20, 2022, (ML22354A161).

10 Wall, S., U.S. Nuclear Regulatory Commission email correspondence to Schultz, NextEra Energy Point Beach, LLC, "Final RAI (Volume 2) - Point Beach 1 & 2 - License Amendment Request Regarding TSTS-505 (EPID No. L-2022-LLA-0074)," dated January 31, 2023 (ML23033A029).

11 U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities,"

RG 1.200, Revision 2, Regulatory Guide 1.200, Revision 2, dated March 2009 (ML090410014).

12 U.S. Nuclear Regulatory Commission, "Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities," Regulatory Guide 1.200, Revision 3, dated December 2020 (ML20238B871).

13 U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," RG 1.174, Revision 2, Regulatory Guide 1.174, Revision 2, dated May 2011 (ML100910006).

14 U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific changes to the Licensing Basis,"

Regulatory Guide 1.174, Revision 3, dated January 2018 (ML17317A256).

15 U.S. Nuclear Regulatory Commission, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," Regulatory Guide 1.177, Revision 0, dated August 1998, (ML003740176).

16 U.S. Nuclear Regulatory Commission, "Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications," Regulatory Guide 1.177, Revision 2, dated January 2021 (ML20164A034).

17 U.S. Nuclear Regulatory Commission, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking," NUREG-1855, Revision 1, dated March 2017 (ML17062A466).

18 U.S. Nuclear Regulatory Commission, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Chapter 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance"," NUREG-0800, dated June 2007 (ML071700658).

19 U.S. Nuclear Regulatory Commission, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Chapter 16.0, "Technical Specifications","

NUREG-0800, Revision 3, dated March 2010 (ML100351425).

20 U.S. Nuclear Regulatory Commission, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Chapter 16.1, "Risk-Informed Decision Making: Technical Specifications"," NUREG-0800, Revision 1, dated March 2007 (ML070380228).

21 Nuclear Energy Institute, "Risk-Informed Technical Specifications Initiative 4b: Risk-Managed Technical Specification (RMTS)," Topical Report NEI 06-09, Revision 0-A, Topical Report NEI 06-09, Revision 0-A, dated October 2012 (ML122860402).

22 Golder, J., U.S. Nuclear Regulatory Commission, letter to Bradley, B., Nuclear Energy Institute, "Final Safety Evaluation For Nuclear Energy Institute (NEI) Topical Report (TR)

NEI 06-09, "Risk-Informed Technical Specifications Initiative 4B, Risk-Managed Technical Specifications (RMTS) Guidelines" (TAC No. MD4995)," dated May 17, 2007, (ML071200238).

23 U.S. Nuclear Regulatory Commission, "Safety Goals for the Operations of Nuclear Power Plants; Policy Statement; Republication," Federal Register (FR), 51 FR 28044; August 4, 1986 as corrected and republished as 51 FR 30028; August 21, 1986.

24 Technical Specifications Task Force, letter to U.S. Nuclear Regulatory Commission, "TSTF-439, Revision 2, "Eliminate Second Completion Times Limiting Time From Discovery of Failure To Meet an LCO"," dated June 20, 2005 (ML051860296).

25 Boyce, T. H., U.S. Nuclear Regulatory Commission, letter to Technical Specifications Task Force, "Status of TSTF-439, "Eliminate Second Completion Times Limiting Time From Discovery of Failure to Meet an LCO"," dated January 11, 2006 (ML00120272).

26 Strope, M., NextEra Energy Point Beach, LLC, Attachment 2 of letter to U.S. Nuclear Regulatory Commission, "License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b'," dated May 20, 2022, (ML22140A134, ML22140A135, and ML22140A136).

27 Strope, M., NextEra Energy Point Beach, LLC, Attachment 4 of letter to U.S. Nuclear Regulatory Commission, "License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b'," dated May 20, 2022, (ML22140A139).

28 Strope, M., NextEra Energy Point Beach, LLC, Enclosures 1, 2 and 3 of letter to U.S.

Nuclear Regulatory Commission, "License Amendment Request 297, Revise Technical Specification to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b," dated May 20, 2022, (ML22140A142).

29 Strope, M., NextEra Energy Point Beach, LLC, Attachement 5 of letter to U.S. Nuclear Regulatory Commission, "License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b'," dated May 20,2022, (ML22140A140).

30 U.S. Nuclear Regulatory Commission, "Standard Technical Specifications Westinghouse Plants," NUREG-1431, Revision 4, Volume 1, dated April 2012 (ML12100A222).

31 U.S. Nuclear Regulatory Commission, "Standard Technical Specifications Westinghouse Plants," NUREG-1431, Revision 1, Volume 1, dated April 1995 (ML13196A405).

32 Strand, D., NextEra Energy, letter to U.S. Nuclear Regulatory Commission, "Periodic Update of the Final Safety Analysis Report," dated October 4, 2022 (ML22284A074).

33 Strope, M., NextEra Energy Point Beach, LLC, Enclosures 11 and 12 of letter to U.S.

Nuclear Regulatory Commission, "License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b'," dated May 20, 2022, (ML22140A145).

34 Strope, M., NextEra Energy Point Beach, LLC, Enclosures 4, 5, 6 and 7 of letter to U.S.

Nuclear Regulatory Commission, "License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b," dated May 20, 2022, (ML22140A143).

35 The American Society of Mechanical Engineers (ASME) and American Nuclear Society (ANS) PRA standard ASME/ANS 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," dated February 2, 2009, New York, NY (Copyright).

36 Nuclear Energy Institute, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," NEI 05-04, Revision 2, dated November 2008, (ML083430462).

37 Nucear Energy Institute, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines," NEI 07-12, Revision 1, dated June 2010, (ML102230070).

38 Strope, M., NextEra Energy Point Beach, LLC, Enclosures 8, 9 and 10 of letter to U.S.

Nuclear Regulatory Commission, "License Amendment Request 297, Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, 'Provide Risk-Informed Extended Completions Times - RITSTF Initiative 4b'," dated May 20, 2022, (ML22140A144).

39 McCartney, E., NextEra Energy Point Beach, LLC, letter to U.S. Nuclear Regulatory Commission, "NextEra Energy Point Beach LLC Seismic Hazard and Screening Report (CEUS Sites) Response NRC Request for Information Pursuant to 10CFR50.54(f)

Regarding Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident," dated March 31, 2014 (ML14090A275).

40 U.S. Nuclear Regulatory Commission, Generic Issue 199, "Results of Safety/Risk Assessment of Generic Issue 199, "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants," dated September 2, 2010 (ML100270582).

41 McCartney, E., NextEra Energy Point Beach, LLC, letter to U.S. Nuclear Regulatory Commission, "NextEra Energy Point Beach, LLC, Response to NRC 10 CFR 50.54(f)

Request for Information Regarding Near-Term Task Force Recommendation 2.1, Flooding

- Submittal of Flooding Hazards Revaluation Report," dated March 12, 2015 (ML15071A413).

42 Coffey, R., NextEra Energy Point Beach, LLC, letter to U.S. Nuclear Regulatory Commission, "NextEra Energy Point Beach LLC, Focused Evaluation for Local Intense Precipitation," dated June 22, 2017 (ML17173A082).

43 Uribe, J. F., U.S. Nuclear Regulatory Commission letter to Craven, R., NextEra Energy Point Beach, LLC, "Point Beach Nuclear Plant, Units 1 and 2 - Staff Assessment of Flooding Focused Evaluation (CAC Nos. MF9865 adn MF9866; EPID L-2017-JLD-0013),"

dated May 30, 2018 (ML18136A700).

44 Link, B., Wisconsin Electric Power Company, letter to U.S. Nuclear Regulatory Commission, "Generic Letter 88-20, Supplement 4 (TAC NOS. 74452 and 74453)

Summary Report on Individual Plant Examination of External Events for Severe Accident Vulnerabilities Point Beach Nuclear Plant, Units 1 and 2," dated June 30, 1995, Non-Public (ML080100398).

45 Nuclear Energy Institute, "Regulatory Assessment Performance Indicator Guideline," NEI 99-02, Revision 7, dated August 31, 2013 (ML13261A116).

46 U.S. Nuclear Regulatory Commission, "NRC Regulatory Issue Summary 2001-11, "Voluntary Submission of Performance Indicator Data," dated May 11, 2001 (ML011240144).

Principal Contributors: KBucholtz, NRR/DRA ABrown, NRR/DRA DWu, NRR/DRA SPark, NRR/DRA CCheung, NRR/DEX NCarte, NRR/DEX CPeabody, NRR/DEX EKleeh, NRR/DEX SWyman, NRR/DEX NKaripineni, NRR/DSS SBhatt, NRR/DSS ARussell, NRR/DSS Date: June 1, 2023

ML23103A133 *by e-concurrence OFFICE NRR/DORL/LPL3/PM NRR/DORL/LPL3/LA NRR/DEX/EEEB/BC* NRR/DEX/EICB/BC*

NAME SWall SRohrer WMorton MWaters DATE 04/12/2023 04/17/2023 03/31/2023 03/31/2023 OFFICE NRR/DSS/STSB/BC* NRR/DSS/SCPB/BC* NRR/DSS/SNSB/BC* NRR/DRA/APLC/BC*

NAME VCusumano BWittick DWoodyatt SVasavada DATE 03/31/2023 03/31/2023 03/31/2023 03/31/2023 OFFICE NRR/DRA/APLA/BC* OGC - NLO NRR/DORL/LPL3/BC(A) NRR/DORL/LPL3/PM NAME RPascarelli MCarpentier VSreenivas SWall DATE 04/05/2023 5/25/2023 5/31/2023 6/1/2023

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

ML23103A133

Text

SUBJECT:

Dear Mr. Coffey:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

3.4 Technical Evaluation Conclusion

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

7.0 REFERENCES

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