Text

Issuance of Amendment Nos. 325 and 306 Revise TS Reactor Trip System Instrumentation and Engineered Safety Features Actuation System Instrumentation Test Times and Completion Times
	ML18318A266
Person / Time
Site:	Salem
Issue date:	12/19/2018
From:	James Kim; Special Projects and Process Branch
To:	Sena P; Public Service Enterprise Group
	Kim J, NRR/DORL/LPL1
References
	EPID L-2017-LLA-0442
	Download: ML18318A266 (36)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 December 19, 2018 Mr. Peter P. Sena, Ill President and Chief Nuclear Officer PSEG Nuclear LLC - N09 Salem Nuclear Generating Station P.O. Box236 Hancocks Bridge, NJ 08038

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2- ISSUANCE OF AMENDMENT NOS. 325 AND 306 RE: REVISE TECHNICAL SPECIFICATION REACTOR TRIP SYSTEM INSTRUMENTATION AND ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION TEST TIMES AND COMPLETION TIMES (EPID L-2017-LLA-0442)

Dear Mr. Sena:

The U.S. Nuclear Regulatory Commission (NRC or the Commission) has issued the enclosed Amendment Nos. 325 and 306 to Renewed Facility Operating License Nos. DPR-70 and DPR-75 for the Salem Nuclear Generating Station, Unit Nos. 1 and 2, respectively. These amendments consist of changes to the Technical Specifications (TSs) in response to your application dated December 18, 2017, as supplemented by letters dated February 9, 2018 and July 17, 2018.

The amendments revise TS 3/4.3.1, "Reactor Trip System Instrumentation," and TS 3/4.3.2, "Engineered Safety Feature Actuation System Instrumentation," to increase the completion times and bypass test times at Salem Nuclear Generating Station, Unit Nos. 1 and 2. The changes are consistent with NRG-approved Technical Specifications Task Force {TSTF)

Travelers TSTF-411, Revision 1, "Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376-P)," and TSTF-418, Revision 2, "RPS [Reactor Protection System] and ESFAS [Engineered Safety Feature Actuation System] Test Times and Completion Times (WCAP-14333)," or are supported by plant-specific analysis.

P. Sena, Ill A copy of the related safety evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, James S. Kim, Project Manager Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-272 and 50-311

Enclosures:

1. Amendment No. 325 to DPR-70

2. Amendment No. 306 to DPR-75

3. Safety Evaluation cc: Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 PSEG NUCLEAR LLC EXELON GENERATION COMPANY, LLC DOCKET NO. 50-272 SALEM NUCLEAR GENERATING STATION, UNIT NO. 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 325 Renewed License No. DPR-70

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

A. The application for amendment filed by PSEG Nuclear LLC, acting on behalf of itself and Exelon Generation Company, LLC (the licensees) dated December 18, 2017, as supplemented by letters dated February 9, 2018 and July 17, 2018, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's 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 Commission's regulations set forth in 10 CFR Chapter I; 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 Commission's 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 2.C.(2) of Renewed Facility Operating License No. DPR-70 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 325, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications, and the Environmental Protection Plan.

3. This license amendment is effective as of its date of issuance and shall be implemented within 90 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Jal~~

Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Renewed Facility Operating License and Technical Specifications Date of Issuance: December 19, 2018

ATTACHMENT TO LICENSE AMENDMENT NO. 325 SALEM NUCLEAR GENERATING STATION, UNIT NO. 1 RENEWED FACILITY OPERATING LICENSE NO. DPR-70 DOCKET NO. 50-272 Replace the following page of Renewed Facility Operating License No. DPR-70 with the attached revised page as indicated. The revised page is identified by amendment number and contains a marginal line indicating the area of change.

Remove Insert Page 3 Page 3 Replace the following pages of the Appendix A, Technical Specifications, with the attached revised pages as indicated. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert 3/4 3-5 3/4 3-5 3/4 3-6 3/4 3-6 3/4 3-7 3/4 3-7 3/4 3-21 3/4 3-21 3/4 3-22 3/4 3-22

instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required;

( 5) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, 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 (6) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30 and 70, to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of 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 or incorporated below:

( 1) Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at a steady state reactor core power level not in excess of 3459 megawatts (one hundred percent of rated core power).

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 325, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications, and the Environmental Protection Plan.

(3) Deleted Per Amendment 22, 11-20-79 (4) Less than Four Loop Operation PSEG Nuclear LLC shall not operate the reactor at power levels above P-7 (as defined in Table 3.3-1 of Specification 3.3.1.1 of Appendix A to this renewed license) with less than four (4) reactor coolant loops in operation until safety analyses for less than four loop operation have been submitted by the licensees and approval for less than four loop operation at power levels above P-7 has been granted by the Commission by Amendment of this renewed license.

(5) PSEG Nuclear LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Renewed License No. DPR-70 Amendment No. 325

TABLE 3.3-1 (Continued)

TABLE NOTATION

With the reactor trip system breakers in the closed position and the control rod drive system capable of rod withdrawal.

1. 1. If ACTION Statement 1 is entered as a result of Reactor Trip Breaker (RTB) or Reactor Trip Bypass Breakers (RTBB) maintenance testing results exceeding the following acceptance criteria, NRC reporting shall be made within 30 days in accordance with Specification 6.9.2:

1. A RTB or RTBB trip failure during any surveillance test with less than or equal to 300 grams of weight added to the breaker trip bar.

2. A RTB or RTBB time response failure that results in the overall reactor trip system time response exceeding the Technical Specification limit.

ACTION STATEMENTS.

ACTION 1 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, restore the inoperable channel (RTB) to OPERABLE within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.1.1.1 provided the other channel is OPERABLE.

ACTION 2 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channels OPERABLE requirement is met; however, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing per Specification 4.3.1.1.1.

c. Either, THERMAL POWER is restricted to s 75% of RATED THERMAL POWER and the Power Range, Neutron Flux trip setpoint is reduced to s 85% of RATED THERMAL POWER within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; or, the QUADRANT POWER TILT RATIO is monitored at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SALEM - UNIT 1 3/4 3-5 Amendment No. 325

TABLE 3.3-1 (Continued)

ACTION 3 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:

a. Below P-6, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint.

b. Above P-6 but below 5% of RATED THERMAL POWER, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above 5% of RATED THERMAL POWER.

c. Above 5% of RATED THERMAL POWER, POWER OPERATION may continue.

ACTION 4 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:

a. Below P-6, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint.

b. Above P-6, operation may continue.

ACTION 5 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, verify compliance with the SHUTDOWN MARGIN requirements of Specification 3.1.1.1 or 3.1.1.2, as applicable, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter.

ACTION 6 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels per Specification 4.3.1.1.1.

ACTION 7 - NOT USED ACTION 8 - NOT USED ACTION 9 - NOT USED SALEM - UNIT 1 3/4 3-6 Amendment No. 325

TABLE 3.3-1 (Continued)

ACTION 1O - With the number of OPERABLE Channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least HOT STANDBY in the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.1.1.1, provided the other channel is OPERABLE.

ACTION 11 - With less than the Minimum Number of Channels OPERABLE, operation may continue provided the inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

ACTION 12 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and/or open the reactor trip breakers.

ACTION 13 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or open the reactor trip breakers within the next hour.

ACTION 14 - With one of the diverse trip features (Undervoltage or shunt trip attachment) inoperable, restore it to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or declare the breaker inoperable and be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The breaker shall not be bypassed while one of the diverse trip features is inoperable except for the time required for performing maintenance to restore the breaker to OPERABLE status.

REACTOR TRIP SYSTEM INTERLOCKS DESIGNATION CONDITION AND SETPOINT FUNCTION P-6 With 2 of 2 Intermediate Range P-6 prevents or defeats the manual block of Neutron Flux Channels source range reactor trip.

< 4.7x10-s % of RTP.

P-7 With 2 of 4 Power Range P-7 prevents or defeats the automatic block Neutron Flux Channels ~ 11 % of reactor trip on: Low flow in more than of RATED THERMAL POWER one primary coolant loop, reactor coolant or 1 of 2 Turbine steam line pump undervoltage and under-frequency, input pressure channels ~ a pressurizer low pressure, pressurizer high pressure equivalent to 11 % of level, and the opening of more than one RATED THERMAL POWER. reactor coolant pump breaker.

SALEM - UNIT 1 3/4 3-7 Amendment No. 325

TABLE 3.3-3 (Continued)

TABLE NOTATION

Trip function may be bypassed in this MODE below P-11.

I#, Trip function may be bypassed in this MODE below P-12.

- Applies to Functional Unit 8 items c and d.

- - The automatic actuation logic includes two redundant solenoid operated vent valves for each Main Steam Isolation Valve. One vent valve on any one Main Steam Isolation Valve may be isolated without affecting the function of the automatic actuation logic provided the remaining seven solenoid vent valves remain OPERABLE. The isolated MSIV vent valve shall be returned to OPERABLE status upon the first entry into MODE 5 following determination that the vent valve is inoperable. For any condition where more than one of the eight solenoid vent valves are inoperable, entry into ACTION 20 is required.

ACTION STATEMENTS ACTION 13- With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or, be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1.1 provided the other channel is OPERABLE.

ACTION 14- With the number of OPERABLE Channels one less than the Total Number of Channels, operation may proceed until performance of the next required CHANNEL FUNCTIONAL TEST, provided the inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

ACTION 15 - NOT USED ACTION 16- With the number of OPERABLE Channels one less than the Total Number of Channels, operation may proceed provided the inoperable channel is placed in the bypassed condition and the Minimum Channels OPERABLE requirement is demonstrated by CHANNEL CHECK within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ; one additional channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing per Specification 4.3.2.1;1.

ACTION 17 - With less than the Minimum Channels OPERABLE, operations may continue provided the containment purge and exhaust valves are maintained closed.

ACTION 18 - With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SALEM - UNIT 1 3/4 3-21 Amendment No. 325

TABLE 3.3-3 (Continued)

ACTION 19 - With the number of OPERABLE Channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channels OPERABLE requirements is met; however, the inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels per Specification 4.3.2.1.1.

ACTION 20 - With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or, be in at least HOT STANDBY within the ne~ 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1.1 provided the other channel is OPERABLE.

ACTION 21 - With the number of OPERABLE channels one less than the Minimum Number of Channels, operation may proceed provided that the inoperable channel is restored to OPERABLE within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

ACTION 22 - NOT USED ACTION 23 - With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SALEM - UNIT 1 3/4 3-22 Amendment No. 325

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 PSEG NUCLEAR LLC EXELON GENERATION COMPANY, LLC DOCKET NO. 50-311 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 306 Renewed License No. DPR-75

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

A. The application for amendment filed by PSEG Nuclear LLC, acting on behalf of itself and Exelon Generation Company, LLC (the licensees) dated December 18, 2017, as supplemented by letters dated February 9, 2018 and July 17, 2018, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's 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 Commission's regulations set forth in 10 CFR Chapter I; 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 Commission's 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 2.C.(2) of Renewed Facility Operating License No. DPR-75 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 306, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. This license amendment is effective as of its date of issuance and shall be implemented within 90 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION 3~~

Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Renewed Facility Operating License and Technical Specifications Date of Issuance: December 19, 2018

ATIACHMENT TO LICENSE AMENDMENT NO. 306 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 RENEWED FACILITY OPERATING LICENSE NO. DPR-75 DOCKET NO. 50-311 Replace the following page of Renewed Facility Operating License No. DPR-75 with the attached revised page as indicated. The revised page is identified by amendment number and contains a marginal line indicating the area of change.

Remove Insert Page 3 Page 3 Replace the following pages of the Appendix A, Technical Specifications, with the attached revised pages as indicated. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert 3/4 3-5 3/4 3-5 3/4 3-6 3/4 3-6 3/4 3-7 3/4 3-7 3/4 3-22 3/4 3-22 3/4 3-23 3/4 3-23

(4) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use at any time any byproduct, source or special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration and as fission detectors in amounts as required; (5) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, 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 (6) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I 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 or incorporated below:

( 1) Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at steady state reactor core power levels not in excess of 3459 megawatts (thermal).

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 306, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Renewed License No. DPR-75 Amendment No. 306

TABLE 3.3-1 (Continued)

TABLE NOTATION

With the reactor trip system breakers in the closed position and the control rod drive system capable of rod withdrawal.

If ACTION Statement 1 is entered as a result of Reactor Trip Breaker (RTB) or Reactor Trip Bypass Breaker (RTBB) maintenance testing results exceeding the following acceptance criteria, NRC reporting shall be made within 30 days in accordance with Specification 6.9.2:

1. A RTB or RTBB trip failure during any surveillance test with less than or equal to 300 grams of weight added to the breaker trip bar.

2. A RTB or RTBB time response failure that results in the overall reactor trip system time response exceeding the Technical Specification limit.

ACTION STATEMENTS ACTION 1 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, restore the inoperable channel (RTB) to OPERABLE within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.1.1.1 provided the other channel is OPERABLE.

ACTION 2 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channels OPERABLE requirement is met; however, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing per Specification 4.3.1.1.1.

c. Either, THERMAL POWER is restricted to s 75% of RATED THERMAL POWER and the Power Range, Neutron Flux trip setpoint is reduced to s 85% of RATED THERMAL POWER within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; or, the QUADRANT POWER TILT RATIO is monitored at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

d. The QUADRANT POWER TILT RATIO, as indicated by the remaining three detectors, is verified consistent with the normalized symmetric power distribution obtained by using either the movable in-core detectors in the four pairs of symmetric thimble locations or the power distribution monitoring system at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when THERMAL POWER is greater than 75% of RATED THERMAL POWER.

SALEM - UNIT 2 3/4 3-5 Amendment No. 306

TABLE 3.3-1 (Continued)

ACTION 3- With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:

a. Below P-6, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint.

b. Above P-6, but below 5% of RATED THERMAL POWER, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above 5% of RATED THERMAL POWER.

c. Above 5% of RATED THERMAL POWER, POWER OPERATION may continue.

d. Above 10% of RATED THERMAL POWER, the provisions of Specification 3.0.3 are not applicable.

ACTION 4 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:

a. Below P-6, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint.

b. Above P-6, operation may continue.

ACTION 5 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, verify compliance with the SHUTDOWN MARGIN requirements of Specification 3.1.1.1 or 3.1.1.2, as applicable, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter.

ACTION 6 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channel OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels per Specification 4.3.1.1.1.

ACTION 7 - NOT USED ACTION 8 - NOT USED ACTION 9 - NOT USED SALEM - UNIT 2 3/4 3-6 Amendment No. 306

TABLE 3.3-1 (Continued)

ACTION 10 - With the number of OPERABLE Channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least HOT STANDBY in the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.1.1.1 provided the other channel is OPERABLE.

ACTION 11 - With less than the Minimum Number of Channels OPERABLE, operation may continue provided the inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

ACTION 12 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and/or open the reactor trip breakers.

ACTION 13 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or open the reactor trip breakers within the next hour.

ACTION 14 - With one of the diverse trip features (Undervoltage or shunt trip attachment) inoperable, restore it to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or declare the breaker inoperable and be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The breaker shall not be bypassed while one of the diverse trip features is inoperable except for the time required for performing maintenance to restore the breaker to OPERABLE status.

REACTOR TRIP SYSTEM INTERLOCKS DESIGNATION CONDITION AND SETPOINT FUNCTION P-6 With 2 of 2 Intermediate Range P-6 prevents or defeats the manual Neutron Flux Channels block of source range reactor trip.

< 4.7x10-a% of RTP.

P-7 With 2 of 4 Power Range Neutron P-7 prevents or defeats the automatic Flux Channels ~ 11 % of RATED block of reactor trip on: Low flow in THERMAL POWER or 1 of 2 more than one primary coolant loop, Turbine steam line inlet pressure reactor coolant pump undervoltage channels ~ a pressure equivalent and under-frequency, pressurizer low to 11 % of RATED THERMAL pressure, pressurizer high level, and POWER. the opening of more than one reactor coolant pump breaker.

SALEM - UNIT 2 3/4 3-7 Amendment No. 306

TABLE 3.3-3 (Continued)

TABLE NOTATION

Trip function may be bypassed in this MODE below P-11.

ti# Trip function may be bypassed in this MODE below P-12.

- Applies to Functional Unit 8 items c and d.

- - The automatic actuation logic includes two redundant solenoid operated vent valves for each Main Steam Isolation Valve. One vent valve on any one Main Steam Isolation Valve may be isolated without affecting the function of the automatic actuation logic provided the remaining seven solenoid vent valves remain OPERABLE. The isolated MSIV vent valve shall be returned to OPERABLE status upon the first entry into MODE 5 following determination that the vent valve is inoperable. For any condition where more than one of the eight solenoid vent valves are inoperable, entry into ACTION 20 is required.

ACTION STATEMENTS ACTION 13 - With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or, be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1.1 provided the other channel is OPERABLE.

ACTION 14 - With the number of OPERABLE Channels one less than the Total Number of Channels, operation may proceed until performance of the next required CHANNEL FUNCTIONAL TEST, provided the inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

ACTION 15 - NOT USED ACTION 16 - With the number of OPERABLE Channels one less than the Total Number of Channels, operation may proceed provided the inoperable channel is placed in the bypassed condition and the Minimum Channels OPERABLE requirement is demonstrated by CHANNEL CHECK within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ; one additional channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing per Specification 4.3.2.1.1.

ACTION 17 - With less than the Minimum Channels OPERABLE, operation may continue provided the containment purge and exhaust valves are maintained closed.

ACTION 18 - With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SALEM - UNIT 2 3/4 3-22 Amendment No. 306

TABLE 3.3-3 (Continued)

ACTION 19 - With the number of OPERABLE Channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channels OPERABLE requirements is met; however, the inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels per Specification 4.3.2.1.1.

ACTION 20 - With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or, be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1.1 provided the other channel is OPERABLE.

ACTION 21 - With the number of OPERABLE channels one less than the Minimum Number of Channels, operation may proceed provided that the inoperable channel is restored to OPERABLE within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

ACTION 22 - NOT USED ACTION 23 - With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SALEM - UNIT 2 3/4 3-23 Amendment No. 306

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NOS. 325 AND 306 TO RENEWED FACILITY OPERATING LICENSE NOS. DPR-70 AND DPR-75 PSEG NUCLEAR LLC EXELON GENERATION COMPANY, LLC SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 DOCKET NOS. 50-272 AND 50-311

1.0 INTRODUCTION

By letter dated December 18, 2017 (Agencywide Documents Access and Management System (ADAMS) Accessi.on No. ML17352A502), as supplemented by letters dated February 9, 2018 (ADAMS Accession No. ML18040A319), and July 17, 2018 (ADAMS Accession No. ML18199A073), PSEG Nuclear LLC (the licensee) submitted a risk-informed license amendment request (LAR) to revise the Salem Generating Station (Salem) Unit Nos. 1 and 2 Technical Specification (TS) 3/4.3.1, "Reactor Trip System Instrumentation," and TS 3/4.3.2, "Engineered Safety Feature Actuation System Instrumentation." These changes are based on Westinghouse Commercial Atomic Power (WCAP)-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the RPS [Reactor Protection System] and ES FAS [Engineered Safety Feature Actuation System] Test Times and Completion Times," and WCAP-15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS [Reactor Trip System] and ES FAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times."

The LAR, as supplemented, is consistent with U.S. Nuclear Regulatory Commission (NRC or the Commission)-approved Technical Specifications Task Force (TSTF) Travelers TSTF-411, Revision 1, "Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376-P)," and TSTF-418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)," or is supported by plant-specific analyses for those changes that are plant-specific, and therefore, are not evaluated in these WCAPs.

The Pressurized Water Reactor Owners Group (PWROG), formerly the Westinghouse Owners Group, Technical Specifications Optimization Program evaluated changes to surveillance test intervals (STls) and completion times (CTs) for the analog channels, logic cabinets, master and slave relays, and reactor trip breakers (RTBs). The methodology evaluated increases in surveillance intervals, test and maintenance out-of-service times, and the bypassing of portions of the RPS during test and maintenance.

Enclosure 3

In 1983, the PWROG submitted WCAP-10271-P, "Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System," which provided a methodology for justifying revisions to a plant's RPS TSs. The PWROG stated in WCAP-10271 that plant staff devoted significant time and effort to perform, review, document, and track surveillance activities that, in many instances, may not be necessary because of the high reliability of the equipment. Part of the justification for the changes was the anticipated small impact on plant risk. By letter dated February 21, 1985, the NRC accepted WCAP-10271, including Supplement 1, with conditions. In 1989, the NRC staff issued a safety evaluation (SE) for WCAP-10271, Supplement 2, which approved similar relaxations for the ESFAS. An additional supplemental SE issued in 1990 provided consistency between RTS and ESFAS STls and CTs.

The NRC subsequently adopted the TS changes proposed by WCAP-10271 in NUREG-1431, Revision 0, "Standard Technical Specifications Westinghouse Plants," issued September 1992.

After the approval of WCAP-10271, and its supplements, the PWROG submitted WCAP-14333-P in May 1995. The purpose of this topical report (TR) was to provide justification for additional TS relaxations beyond those approved in WCAP-10271. The NRC staff accepted WCAP-14333 by letter dated July 15, 1998. Following the approval of WCAP-14333, the PWROG submitted WCAP-15376 to the NRC staff on November 8, 2000, which the staff subsequently approved by letter dated December 20, 2002. WCAP-15376 specifically evaluated the analog channels, logic cabinets, master relays, RTBs, solid state protection system (SSPS), and the relay protection system.

The proposed changes to the STls described in TSTF-411 and TSTF-418 are not included in this LAR. The Salem STls are controlled under the Surveillance Frequency Control Program.

Salem Amendment Nos. 299 and 282, dated March 21, 2011 (ADAMS Accession No. ML110410691 ), modified the TSs by relocating specific surveillance frequencies to a licensee-controlled program based on TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - RITSTF [Risk-Informed TSTF] Initiative Sb."

2.0 REGULATORY EVALUATION

2.1 Regulatory Criteria and Guidance The NRC staff's evaluation is based on the following guidance and regulations:

Title 10 of the Code of Federal Regulations (10 CFR) Section 50.36, "Technical specifications,"

paragraph (a)(1 ), states, "Each applicant for a license authorizing operation of a production or utilization facility shall include in his application proposed technical specifications in accordance with the requirements of this section." Specifically, 10 CFR 50.36(c)(2)(ii) sets forth four criteria to be used in determining whether a limiting condition for operation is required to be included in the TSs.

Appendix A, "General Design Criteria" (GDC) to 10 CFR Part 50 GDC 13, "Instrumentation and control," demonstrates that instrumentation shall be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for accident conditions, as appropriate, to assure adequate safety, including those variables and systems affecting the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems.

GDC 21, "Protection system reliability and testability," requires that the system be designed for high functional reliability and inservice testability, with redundancy and independence sufficient

to preclude loss of the protection function from a single failure and preservation of minimum redundancy, despite removal from service of any component or channel.

GDC 22, "Protection system independence," requires that the system be designed so that natural phenomena, normal operating, maintenance, testing, and postulated accident conditions do not result in loss of the protection function.

NUREG-1431, Revision 4.0, Volume 1, "Standard Technical Specifications, Westinghouse Plants" (ADAMS Accession No. ML12100A222), contains the improved Standard Technical Specifications for Westinghouse plants.

Regulatory Guide (RG) 1.174, Revision 2, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" (ADAMS Accession No. ML100910006), describes a risk-informed approach with associated acceptance guidelines for licensees to assess the nature and impact of proposed permanent licensing basis changes by considering engineering issues and applying risk insights. In implementing risk-informed decisionmaking, the NRC expects licensing basis changes to meet the acceptance guidelines and key principles of risk-informed regulation specified in RG 1.174.

RG 1.177, Revision 1, "An Approach for Plant-Specific, Risk-Informed Decision making:

Technical Specifications" (ADAMS Accession No. ML100910008), describes an acceptable risk-informed approach and additional acceptance guidelines geared toward the assessment of proposed permanent TS CT changes. RG 1.177 identifies a three-tiered approach for the licensee's evaluation of the risk associated with a proposed TS CT change, as discussed below:

Tier 1 assesses the risk impact of the proposed change in accordance with acceptance guidelines consistent with the Commission's Safety Goal Policy Statement, as documented in RG 1.174 and RG 1.177. The first tier assesses the impact on operational plant risk based on the change in core damage frequency (l1CDF) and change in large early release frequency (l1LERF). It also evaluates plant risk while equipment covered by the proposed CT is out of service, as represented by incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP). Tier 1 also addresses probabilistic risk assessment (PRA) quality, including the technical

adequacy of the licensee's plant-specific PRA for the subject application.

Tier 2 identifies and evaluates any potential risk-significant plant equipment outage configurations that could result if equipment, in addition to that associated with the proposed license amendment, is taken out of service simultaneously, or if other risk-significant operational factors such as concurrent system or equipment testing, are also involved. The purpose of this evaluation is to ensure that appropriate restrictions are in place such that risk-significant plant equipment outage configurations will not occur when equipment associated with the proposed CT is implemented.

Tier 3 addresses the licensee's overall configuration risk management program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and that the licensee takes appropriate compensatory measures to avoid risk-significant configurations that may not have been considered during the Tier 2 evaluation. Compared with Tier 2, Tier 3 provides additional

coverage to ensure that the licensee identifies risk-significant plant equipment outage configurations in a timely manner and appropriately evaluates the risk impact of out-of-service equipment before performing any maintenance activity over extended periods of plant operation. Tier 3 guidance can be satisfied by the Maintenance Rule (Section (a)(4)), which requires a licensee to assess and manage the increase in risk that may result from activities such as surveillance testing and corrective and preventive maintenance, subject to the guidance provided in RG 1.177, Section 2.3.7.1, and the adequacy of the licensee's program and PRA model for this application. The purpose of the CRMP is to ensure that the licensee will appropriately assess, from a risk perspective, equipment removed from service before or during the proposed extended CT.

RG 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (ADAMS Accession No. ML090410014),

describes an acceptable approach for determining whether the technical adequacy of the PRA is sufficient to support using the PRA in regulatory decisionmaking. RG 1.200 endorses, with clarifications and qualifications, the use of the American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) Standard, RA-Sa-2009, "Addenda to ASME RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications."

Section 50.65 of 10 CFR, known as the "Maintenance Rule," requires licensees to monitor the performance or condition of systems, structures, and components (SSCs) against licensee established goals in a manner sufficient to provide reasonable assurance that SSCs are capable of fulfilling their intended functions. The implementation and monitoring program guidance of Section 3 of RG 1.174 and Section 3 of RG 1.177 states that monitoring performance in compliance with the Maintenance Rule can be used when it is sufficient for the SSCs affected by the risk-informed application. In addition, the Maintenance Rule (10 CFR 50.65(a)(4)), as it relates to the proposed surveillance, bypass test times, and CTs, requires the assessment and management of the increase in risk that may result from the proposed maintenance activity.

Section 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance," of NU REG 0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," dated June 2007 (ADAMS Accession No. ML071700658), hereafter referred to as the Standard Review Plan (SRP),

provides general guidance for evaluating the technical basis for proposed risk-informed changes. SRP Section 16.1, "Risk-Informed Decision Making: Technical Specifications," dated March 2007 (ADAMS Accession No. ML070380228), provides more specific guidance related to risk-informed TS changes, including CT changes as part of risk-informed decisionmaking. SRP Section 19.1, Revision 3, "Determining the Technical Adequacy of Probabilistic Risk Assessment for Risk-Informed License Amendment Requests After Initial Fuel Load," dated September 2012 (ADAMS Accession No. ML12193A107), addresses the technical adequacy of a baseline PRA used by a licensee to support license amendments for an operating reactor.

SRP Section 19.2 states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following five key principles in RG 1.174 and RG 1.177:

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

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

3. The proposed change maintains sufficient safety margins.

4. When proposed changes result in an increase in core damage frequency (CDF) or risk, the increases should be small and consistent with the intent of the Commission's Safety Goal Policy Statement.

5. The impact of the proposed change should be monitored using performance measurement strategies.

2.2 Proposed TS Changes The proposed changes revise the Salem, Unit Nos. 1 and 2, TS Table 3.3-1, "Reactor Trip System Instrumentation," Actions 1, 2, 6, 10, and 11, and TS Table 3.3-3, "Engineered Safety Feature Actuation System Instrumentation," Actions 13, 14, 16, 19, and 20. In general, the changes include increasing the CTs and bypass test times.*

TS 3/4.3.1, "Reactor Trip System Instrumentation" Specifically, the proposed changes would revise the following functions in TS Table 3.3-1, consistent with the generic evaluations approved in WCAP-10271, as supplemented; WCAP-14333; or WCAP-15376:

Instruments Associated with TS Table 3.3-1, "Reactor Trip System Instrumentation" IF unction !System jActionlProposed Technical Specification Change I

l2 Power Range, Neutron Flux 2 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

~nd bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 3 Power Range, Neutron Flux 2 . Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months High Positive Rate and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 7 Overtemperature AT 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 8 Overpower AT 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 9 Pressurizer Pressure - Low 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

~nd bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 10 Pressurizer Pressure - High 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 11 Pressurizer Water Level - 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months High ~nd bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 12 Loss of Flow - Single Loop 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Above P-8) and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 13 Loss of Flow - Two Loops 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

Above P-7 and Below P-8) and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

14 Steam Generator Water 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Level - Low-Low land bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 16 Undervoltage - Reactor 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Coolant Pumps land bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 17 Underfrequency - Reactor 6 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Coolant Pumps land bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Ifurbine Trip la. Low autostop Oil Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 18.a/b Pressure 6 land bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

b. Turbine Stop Valve Closure 19 Safety Injection Input from 10 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ESF Reactor Coolant Pump

~o Breaker Position Trip 11 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Above P-7) 21 Reactor Trip Breakers 1 Increase completion time to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and bypass

~ime from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 22 ~utomatic Trip Logic 10 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months The following TS Table 3.3-1 actions are revised:

Action 1 With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, restore the inoperable channel (RTB} to OPERABLE within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.1.1.1, provided the other channel is OPERABLE.

Action 2 With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied.

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channels OPERABLE requirement is met; however, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing per Specification 4.3.1.1.1.

c. Either, THERMAL POWER is restricted to s 75% of RATED THERMAL POWER and the Power Range, Neutron Flux trip setpoint is reduced to s 85% of RATED THERMAL POWER within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; or, the QUADRANT POWER TILT RATIO is monitored at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Action 6 With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels per Specification 4.3.1.1.1.

Action 10 With the number of OPERABLE Channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least HOT STANDBY in the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.1.1.1, provided the other channel is OPERABLE.

Plant-Specific Evaluations for Functions Not Evaluated Generically with WCAP-14333 The following function in TS Table 3.3-1 was not included in the generic evaluations approved in either WCAP-10271, as supplemented, or WCAP-14333. The TSTF-418, Insert 19, reviewer's note states, "In order to apply the WCAP-10271, as supplemented, or WCAP-14333 TS relaxations to plant specific functions not evaluated generically, licensees must submit plant-specific evaluations for NRC review and approval."

Instruments Associated with TS Table 3.3-1, "Reactor Trip System Instrumentation" Function System Action Proposed Technical Specification Change Reactor Coolant Pump 20 Breaker Position Trip 11 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to (above P-7) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months TS Table 3.3-1, Action 11, is revised as follows:

Action 11 With less than the Minimum Number of Channels OPERABLE, operation may continue provided the inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

TS 3/4.3.2, "Engineered Safety Feature Actuation System Instrumentation" The following functions in TS Table 3.3-3 would be revised, consistent with the generic evaluations approved in eitherWCAP-10271, as supplemented, orWCAP-14333:

Instrumentation Associated with TS Table 3.3-3, "Engineered Safety Feature Actuation System Instrumentation":

Function System ~ction Proposed Technical Specification Change Safety Injection, Turbine Trip and Feedwater Isolation Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 1.b b. Automatic Actuation Logic 13 124 hours0.00144 days 0.0344 hours 2.050265e-4 weeks 4.7182e-5 months Safety Injection, Turbine Trip and Feedwater Isolation

" Containment Pressure I.,,

-High

d. Pressurizer Pressure -Low Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 1.c/d/e/f e. Differential Pressure 19 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to Between Steam Lines -High 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months f

Steam Flow in Two Steam Lines- High Containment Spray Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 12.b b. Automatic Actuation Logic 13 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Containment Spray Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 12.c c. Containment Pressure 16 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to

.... High-High 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Containment Isolation, Phase A Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 3.a.2 ~.2) From Safety Injection 13 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Automatic Actuation Logic Containment Isolation, 3.b.2 Phase B 13 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to b.2) Automatic Actuation Logic 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Containment Isolation, 3.b.3 Phase B 16 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to b.3) Containment Pressure - 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to High-High 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Steam Line Isolation Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 4.b b. Automatic Actuation Logic 120 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Steam Line Isolation Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to i4.c c. Containment Pressure - 16 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to High-High 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Steam Line Isolation Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to

~.d d. Steam Flow in Two Steam 19 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to Lines- High 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

5.a !Turbine Trip & Feedwater 19 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to Isolation 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

!Auxiliary Feedwater Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 8.a la. Automatic Actuation Logic 120 * ~4 hours

!Auxiliary Feedwater C Stm. Gen. Water Level-8.c/d Low-Low 19 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to

~ Undervoltage- RCP Start 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to

!Turbine - Driven Pump 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months The following TS Table 3.3-3 actions are revised as follows:

Action 13 With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or, be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1.1 provided the other channel is OPERABLE.

Action 16 With the number of OPERABLE Channels one less than the Total Number of Channels, operation may proceed provided the inoperable channel is placed in the bypassed condition and the Minimum Channels OPERABLE requirement is demonstrated by CHANNEL CHECK within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ; one additional channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing per Specification 4.3.2.1.1.

Action 19 With the number of OPERABLE Channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. The Minimum Channels OPERABLE requirements is met; however, the inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels per Specification 4.3.2.1.1.

Action 20 With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or, be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1.1 provided the other channel is OPERABLE.

Plant-Specific Evaluations for Functions Not Evaluated Generically with WCAP-14333:

In Table, 3.3-3, Functions 7.a and 7.b, loss of power, was not included in the generic evaluations approved in eitherWCAP-10271, as supplemented, orWCAP-14333. The TSTF-418, Insert 19, reviewer's note states, "In order to apply the WCAP-10271, as supplemented, orWCAP-14333 TS relaxations to plant specific Functions not evaluated generically, licensees must submit plant specific evaluations for NRC review and approval."

In Table, 3.3-3, Function 9.a (Semiautomatic Transfer to Recirculation (SA), Unit 2 Only for RWST Level Low) was not included in the generic evaluations approved in either WCAP-10271, as supplemented, or WCAP-14333. The TSTF-418, Insert 14, reviewer's note states, "In order to apply the WCAP-10271, as supplemented, and WCAP-14333 TS relaxations to plant specific Functions not evaluated generically, licensees must submit plant specific evaluations for NRC review and approval."

In Table, 3.3-3, Functions 3.c.2, 6, and 9.b were not included in the generic evaluations approved in either WCAP-10271, as supplemented, or WCAP-14333. In order to apply the various relaxations justified in WCAP-10271 and WCAP-14333 to plant-specific functions not evaluated generically, a plant-specific evaluation of those functions has been performed.

Instruments Associated with TS Table 3.3-3, "Engineered Safety Feature Actuation System Instrumentation" Function System !Action Proposed Technical Specification Change Containment Isolation (Cl) 3.c.2 c.2) Automatic Actuation 13 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Logic 6 Safeguards Equipment 13 Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Control System (SEC)

Vital Bus Undervoltage (UV)

a. Loss of Voltage 7.a/b b. Sustained Degraded 14 Increase completion time from 1 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Voltage Semiautomatic Transfer to 9.a Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 Recirculation (SA) (Unit 2 16 hours 9.a/b Only) Increase bypass time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12

a. RWST Level Low Hours

b. Automatic Actuation Logic 9.b Increase completion time from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 20 hours The following TS Table 3.3-3, Action 14, is revised as follows:

Action 14 With the number of OPERABLE Channels one less than the Total Number of Channels, operation may proceed until performance of the next required CHANNEL FUNCTIONAL TEST, provided the inoperable channel is placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The proposed changes revise the Salem, Unit Nos. 1 and 2, TS Table 3.3-1, "Reactor Trip System Instrumentation," Actions 1, 2, 6, 10, and 11, and Table 3.3-3, "Engineered Safety Feature Actuation System Instrumentation," Actions 13, 14, 16, 19, and 20. In general, the changes include increasing the CTs and bypass test times.

LAR Attachment 3 also includes proposed changes to the TS Bases. However, these changes are provided for information only.

3.0 TECHNICAL EVALUATION

In accordance with SRP Sections 16.1, 19.1, and 19.2, the NRC staff reviewed the Salem incorporation of WCAP-15376 and WCAP-14333 using the three-tiered approach and the five key principles of risk-informed decision making presented in RG 1.174, Revision 2, and RG 1.177, Revision 1, and the conditions and limitations forWCAP-15376 and WCAP-14333 in SEs dated December 20, 2002, and July 15, 1998, respectively.

The following sections present the NRC staff's evaluation of the licensee's proposed amendment to extend CTs and bypass test times using the three-tiered approach and the five key principles outlined in RG 1.174 and RG 1.177.

3.1 Traditional Engineering Evaluation (Key Principles 1. 2. and 3)

WCAP-14333 permits relaxation of allowed bypass and test times for RTS and ESFAS to be as follows:

Completion Times of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for inoperable instruments

Bypass times of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing

Completion Times of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for an inoperable logic cabinet or master and slave relays The following table is a summary of the changes in WCAP-14333 for the RPS and ESFAS (solid state protection system (SSPS)).

(Note: Salem, Unit Nos. 1 and 2, have the SSPS.)

ComDonent Initial ADDroved

- Maintenance Time 1 6+6 hours 72+6 hours

- Maintenance Interval 2 years 2 years

- Test (bypass) Time 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

- Test Interval 3 months 3 months

- Calibration Interval I NEAPJ 18 months

- Calibration Time I NEAPJ 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

- Maintenance Time 1 6+6 hours 24+6 hours

- Maintenance Interval 18 months 18 months

- Test (bypass) Time 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

- Test Interval 2 months 2 months

- Maintenance Time 1 6+6 hours 24+6 hours

- Maintenance Interval see Note 2 see Note 2

- Test (bypass) Time 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

- Test Interval 2 months 2 months

- Maintenance Time 1 6+6 hours 24+6 hours

- Maintenance Interval see Note 2 see Note 2

- Test (bypass) Time 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

- Test Interval 3 months 3 months

- Maintenance Time 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months

- Maintenance Interval 1 year 1 year

-Test Time 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months

- Test Interval 2 months 2 months Notes:

1 The "6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months " is the time provided in the TS to enter the specified mode if the component is not returned to operable status.

2 Maintenance interval is based on the component failure rate.

3 Not evaluated at-power (NEAP) in the past this activity has typically been done while shut down.

WCAP-15376 permits relaxation of allowed outage time from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and the bypass time from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , for RTBs for both the SSPS and the Relay Protection System.

3.1.1 Evaluation of Changes to RTS The NRC staff reviewed the proposed changes against the approved TSTF-411, Revision 1 and TSTF-418, Revision 2. The NRC letter dated August 30, 2002 (ADAMS Accession No. ML022460347) approved TSTF-411, Revision 1, without changes and advised Westinghouse to include TSTF-411, Revision 1, with publication of approved WCAP-15376-P.

Similarly, the NRC staff approved TSTF-418, Revision 2, pertaining to WCAP-14333, without changes by letter dated April 2, 2003 (ADAMS Accession No. ML030920633). Based on these approvals, TSTF-411, Revision 1, and TSTF-418, Revision 2, reflect the approved versions of WCAP-15376 and WCAP-14333.

The NRC staff reviewed the proposed changes and the associated action statements regarding RTS instrumentation pertaining to Functions 2, 3, and 7 through 14, 16, 18, 18a/b, and 19 through 22. The changes were compared with approved TSTF-411 and TSTF-418 and found acceptable.

RTS Function 20, pertaining to "Reactor Coolant Pump Breaker Position Trip (above P-7)," was not approved generically as part of the approved TSTFs and was submitted as a plant-specific change to be evaluated by the NRC staff. Plant-specific changes are evaluated in Section 3.1.3 of this SE.

3.1.2 Evaluation of Changes to ESFAS The NRC staff reviewed the proposed changes and the associated action statements regarding ESFAS instrumentation pertaining to Functions 1.b, 1.c/d/e/f, 2b, 2c, 3.a.2, 3.b.2, 3.b.3, 4.b, 4.c,

4.d, 5.a, 8.a, and 8.c/d. The changes were compared with approved TSTF-411 and TSTF-418 and found acceptable.

The following ESFAS functions were not included in the generic evaluation, and they require plant-specific evaluations for acceptance by the NRC staff. These plant-specific changes are evaluated in Section 3.1.3 of this SE.

Function System 3.c.2 Containment Isolation (Cl), Automatic Actuation Logic 6 Safeguards Equipment Control System (SEC) 7.a/b Vital Bus Undervoltage (UV)

a. Loss of Voltage

b. Sustained Degraded Voltage 9.a/b Semiautomatic Transfer to Recirculation System (SA) (unit 2 only)

a. RWST Level Low

b. Automatic Actuation Logic 3.1.3 Deterministic Assessment The purpose of the deterministic assessment is to address the traditional engineering considerations for the proposed changes. The traditional engineering evaluation addresses key principles 1, 2, 3, and 5 of the NRC staff's philosophy of risk-informed decisionmaking, which concern compliance with current regulations, evaluation of defense in depth, evaluation of safety margins, and performance measurement strategies. These considerations are needed to address how defense in depth will be maintained. Several factors have been listed in the LAR to address this issue. These factors include avoidance of over-reliance on programmatic activities, preservation of system redundancy, independence, diversity, defense against common cause failures and prevention of new common cause failures, maintaining independence of physical barriers, preserving defense against human error, and maintenance of intent of the plant design criteria. The LAR provides detailed discussions for each of these items in Section 4.1.1. The NRC staff reviewed the licensee's statements and finds that the discussion addresses these items adequately and the statements are acceptable to the staff.

Section 4.1.2 of the LAR addresses safety margin. To assess the safety margin, a review of adherence to codes and standards has been conducted. In addition, review of safety-analysis acceptance criteria in the Final Safety Analysis Report has been conducted to assure that the existing criteria are maintained and new changes do not reduce the safety margin. The discussion in the LAR for both these items has been reviewed by the NRC staff and found adequate.

3.2 Risk Evaluation (Key Principle 4)

WCAP-14333 and WCAP-15376 are consistent with the NRC approach for using PRA in risk-informed decisions on plant-specific changes to the current licensing basis, as presented in RG 1.174 and RG 1.177. The risk evaluation considered the three-tiered approach, as presented by RG 1.177, for the extension to the RTS and ESFAS CTs. Tier 1, PRA Capability and Insights, assesses the impact of the proposed CT and bypass time change on CDF, LERF,

ICCDP, and ICLERP. Tier 2, Avoidance of Risk-Significant Plant Configurations, considers potential risk-significant plant operating configurations. Tier 3, Risk-Informed Plant Configuration Control and Management, is addressed when the TS CT change is implemented.

3.2.1 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed changes on plant operational risk, based on the Salem implementation of WCAP-14333 and WCAP-15376. In Tier 1, the NRC staff review involves the evaluation of the validity of the licensee's PRA and its application to the proposed changes, and evaluation of the PRA results and insights based on the licensee's proposed application.

3.2.1.1 PRA Quality The objective of the PRA quality review is to determine whether the Salem PRA model used to implement WCAP-14333 and WCAP-15376 is of sufficient scope, detail, and technical acceptability for this application. The licensee provided PRA quality information for the internal events PRA model, including internal flooding and a bounding analysis for external flooding in LAR Attachment 1. The licensee provided a bounding analysis for fires and seismic hazards in the LAR supplement dated February 9, 2018. The NRC staff evaluated the PRA quality information provided by the licensee, including industry peer review results; the peer review facts and observations (F&Os) for the internal events PRA; and the bounding analyses for fires, external flooqing, and seismic hazards.

Internal Events PRA LAR Attachment 1 states the licensee performed a full-scope peer review for the internal events

PRA model, including internal flooding, in November 2008 against the requirements of the 2005 ASME PRA standard and RG 1.200, Revision 1, using the process defined in Nuclear Energy Institute (NEI) 05-04, Revision 1, "Process for Performing Follow-On PRA Peer Reviews Using the ASME PRA Standard (Internal Events)." The licensee provided a gap assessment between RG 1.200, Revisions 1 and 2, and a gap assessment between the 2005 ASME PRA standard and the 2009 ASME/ANS PRA standard in LAR Attachment 1, Table 4-19. The licensee also provided a listing of supporting requirements that were revised between the 2005 ASME PRA standard and the 2009 ASME/ANS PRA standard, along with the description of the change and associated comments and dispositions in LAR Attachment 1, Table 4-18.

The NRC staff reviewed the gap assessments and dispositions in Tables 4-18 and 4-19, and concludes that the licensee has adequately addressed the differences between the previous revision of RG 1.200 and the current version, as well as the differences between the 2005 PRA standard and the 2009 PRA standard. Based on the preceding discussion, the staff finds the internal events PRA model for Salem has been adequately assessed against the current version of RG 1.200 and the 2009 PRA standard.

LAR Attachment 1 provides information about the licensee's maintenance and update of the PRA model of record. The NRC staff evaluated this information and has found the licensee has sufficient procedure updates to review plant changes, procedures, and operating history. The licensee also has a schedule to track and implement PRA updates and maintenance. The staff concludes the licensee has a program in place to ensure the PRA model is updated to reflect the as-built, as operated plant.

The licensee provided the disposition of each open F&O not meeting Capability Category II as a result of the November 2008 peer review. In Request for Additional Information (RAI) 2 associated with F&Os AS-A8, AS-B7, and SY-B11, by e-mail dated June 20, 2018 (ADAMS Accession No. ML18171A321), the NRC staff requested the licensee to justify using a 6.2-hour mission time for emergency diesel generators (EDGs) in its PRA model, since the ASME PRA standard states to use a minimum 24-hour mission time; otherwise mission times less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months must be properly modeled in the PRA.

In response to RAI 2 by letter dated July 17, 2018 (ADAMS Accession No. ML18199A073), the licensee stated the 6.2-hour EDG mission time was a surrogate time developed as a time-averaged value for which the EDG would be required to perform its design function for the plant to reach a steady-state condition. This calculation was performed using approved NRC guidance found in NUREG/CR-6890, "Reevaluation of Station Blackout Risk at Nuclear Power Plants." In addition, the licensee stated the change in unavailabilities of the RTS and ESFAS components due to extending CTs has negligible impact on the EDG's ability to start and run, and the bounding calculations for external hazards do not depend on EDG mission time. The NRC staff finds the licensee's resolution to F&Os AS-A8, AS-B7, and SY-B11 acceptable because the licensee adequately modeled and justified the use of a 6.2-hour mission time for the EDG in its PRA.

In RAI 3 by letter dated June 20, 2018, associated with F&O SY-B3, the licensee stated a few common cause failure (CCF) events were determined using sources other than NRG/Idaho National Lab (INL) data (CCF Parameter Estimations, 2012 Update). In order to conclude the licensee's treatment of CCF is reasonable, the NRC staff requested the licensee to provide the other sources of CCF data that were not NRC/INL data. In response to RAI 3 by letter dated July 17, 2018, the licensee confirmed the sources of CCF data were from INL and NUREG/CR-5500, "Reliability Study: Westinghouse Reactor Protection System, 1984-1995."

Based on the licensee's response to RAI 3, the staff finds the disposition of F&O SY-B3 acceptable, since the licensee used CCF data endorsed by the NRC.

In RAI 4 by letter dated June 20, 2018 associated with F&O DA-C5, the NRC staff requested the licensee to justify a discrepancy between its disposition of the F&O and what is stated in the ASME PRA standard. For F&O DA-C5, the licensee stated in its disposition that repetitive failures occurring within a short time can be excluded, while the ASME PRA standard says to count these failures as a single failure. In response to RAI 4 by letter dated July 17, 2018, the licensee clarified that failures occurring within a short time were counted as a single failure, which is in alignment with the ASME PRA standard. The staff finds the disposition of F&O DA-C5 to be acceptable based on the correction the licensee provided in its response to RAI 4.

Based on the preceding discussion, the NRC staff finds the internal events PRA model for Salem has been adequately peer reviewed against the current version of RG 1.200 and the 2009 PRA standard. Based on sufficient response to the RAls and the disposition of the remaining open F&Os, the licensee has adequately dispositioned all open F&Os to support the technical acceptability of the internal events PRA for the implementation of WCAP-14333 and WCAP-15376.

Fire PRA The licensee's PRA model of record does not account for risk associated with internal fires. The licensee provided in LAR Attachment 1 an assessment of the risk associated with fires using insights from an Individual Plant Examination of External Events using the Electric Power

Research Institute (EPRI) Fire-Induced Vulnerability Evaluation (FIVE) methodology, in conjunction with a non-peer-reviewed work-in-progress fire PRA. The ASME PRA standard and RG 1.200 do not endorse the EPRI FIVE methodology and a non-peer-reviewed work-in-progress fire PRA.

The licensee provided a bounding analysis of risk due to fires in LAR supplement dated February 9, 2018, using its internal events PRA model. The licensee concluded that the risk increase from fires due to implementation of WCAP-14333 and WCAP-15376 is well below the risk acceptance guidelines. The NRC staff evaluated the bounding analysis provided by the licensee and finds that the bounding analysis addresses all of the safety functions that would be impacted by fires from extending the CT and bypass times from implementing WCAP-14333 and WCAP-15376. The staff concludes the most bounding scenario is a fire-induced loss-of-coolant accident from reactor coolant pump (RCP) seal failure, and the increase in risk from this scenario is well below the risk acceptance guidelines in RG 1.174 and RG 1.177.

Seismic PRA The licensee's PRA model of record also does not account for risk associated with seismic events. The licensee provided in LAR Attachment 1 an assessment of the risk associated with seismic events using insights from the Individual Plant Examination of External Events. The licensee does not have a seismic PRA that is peer reviewed against the standards of RG 1.200 and the ASME PRA standard.

The licensee provided a bounding analysis of risk due to seismic events in its LAR supplement dated February 9, 2018, using its internal events PRA model. The licensee concluded that the risk increase from seismic events due to implementation of WCAP-14333 and WCAP-15376 is negligible. The NRC staff evaluated the bounding analysis provided by the licensee and finds that the bounding analysis addresses all of the safety functions that would be impacted by seismic events from extending the CT and bypass times from implementing WCAP-14333 and WCAP-15376. The staff concludes the most bounding scenario is a seismically-induced small loss-of-coolant accident, and the increase in risk from this scenario is negligible in accordance with the guidance in RG 1.174. Although the licensee's PRA model does not account for risk associated with seismic events, the staff concludes from the bounding analysis that the increase in risk due to seismic events will not change the conclusions to meet the acceptance guidelines in RG 1.174and RG 1.177.

Other External Hazards In LAR Attachment 1, the licensee provided a bounding analysis using its internal events PRA model and determined the bounding scenario for all other external events was due to external flooding causing a loss-of-offsite power (LOOP). Due to the rarity of an external flooding event causing a loss-of-offsite power, the licensee concluded from the bounding analysis that the risk contribution due to other external hazards is negligible. The NRC staff reviewed the bounding analysis for other external hazards and concludes an external flooding event that causes a loss-of-offsite power is bounding and acceptable. Based on the provided analysis, the staff concludes the risk contribution due to an external flooding event is negligible and will not change the conclusions to meet the acceptance guidelines in RG 1.174 and RG 1.177.

PRA Quality Conclusions Based on the NRC staff's review of the information provided by the licensee on the Salem PRA model provided in the LAR and supplement, the staff concludes that the Salem PRA model for internal events satisfies the guidance of RG 1.200. The staff based this conclusion on the finding that the internal events PRA model conforms to the 2009 ASME/ANS PRA standard for internal events, as endorsed by RG 1.200, Revision 2, at the appropriate capability category.

The staff finds the change in risk due to fire, seismic, and other external events to be well below the risk acceptance guidelines in RG 1.174 and RG 1.177. The staff finds the licensee's PRA acceptable to support implementation of WCAP-14333 and WCAP-15376 because the licensee has reviewed the Salem full power internal events PRA model of record using NRG-endorsed guidance and adequately resolved all issues; the contribution to external events (i.e., fires, seismic, and other external hazards) is sufficiently bounding and the risk impact is well below the risk acceptance guidelines; and the licensee has established a periodic update and review process to update the PRA to incorporate changes to the plant, PRA methods, and data.

3.2.1.2 PRA Results and Insights The licensee provided baseline CDF and LERF values for Salem in LAR Attachment 1, Section 4.3.4. The reported baseline CDF for all hazards was 4.09E-5/year for Unit No. 1 and 4.02E-5/year for Unit No. 2. The reported baseline LERF was 4.47E-7/year for Unit No. 1 and 4.42E-7/year for Unit No. 2. The licensee also provided the risk metrics for the proposed change from the unavailabilities of RTS and ESFAS instrumentation as a result of implementing WCAP-14333 and WCAP-15376.

In LAR supplement Section 4.3.2, dated February 9, 2018, the licensee provided bounding

~CDF and ~LERF values for fire and seismic events, but does not specify which unit the change in risk is applicable to. In response to RAI 5 by letter dated July 17, 2018, the licensee clarified that the change in risk from the LAR supplement due to external hazards is applicable to both units, as the inputs into the PRA are identical to both units. The NRC staff concludes from the licensee's response that the bounding ~CDF and ~LERF values for fire and seismic events are applicable to both units. The calculated risk metrics are summarized in Table 1 for Salem, Unit No. 1, and Table 2 for Salem, Unit No. 2, below:

Table 1: Calculated Risk Metrics for Salem, Unit No. 1

~CDF (/year) ~LERF (/year) ICCDP

~CDF Internal Events 1.68E-9 ~LERF Internal 2.24E-10 7.32E-9 Events

~CDF Fire 5.80E-8 ~LERF Fire 1.60E-10

~CDF Seismic 2.50E-11 ~LERF Seismic 3.60E-11 ICLERP

~CDF Other 1.10E-9 ~LERF Other 6.10E-11 1.75E-9

~CDF Total 6.08E-8 ~LERF Total 4.81E-10 Table 2: Calculated Risk Metrics for Salem, Unit No. 2

~CDF (/year) ~LERF (/year) ICCDP

~CDF Int. Events 3.84E-9 ~LERF Int. 6.65E-10 3.68E-9 Events

~CDF Fire 5.80E-8 ~LERF Fire 1.60E-10

.:1CDF Seismic 2.50E-11 .:1LERF Seismic 3.60E-11 ICLERP

.:1CDF Other 1.50E-9 .:1LERF Other 7.60E-11 8.04E-10

.:1CDF Total 6.34E-8 .:1LERF Total 9.37E-10 For Salem, Unit No. 1, the NRC staff finds that given the total baseline for CDF was 4.09E-5/year, and the calculated .:1CDF was 6.08E-8/year, the risk metric for .:1CDF satisfies the RG 1.174 acceptance guidelines and is considered to be a "very small" change in risk. The staff also finds that given the total baseline LERF was 4.47E-7/year, and the calculated .:1LERF was 4.81 E-10/year, the risk metric for .:1LERF satisfies the RG 1.174 acceptance guidelines and is considered to be a "very small" change in risk. The calculated ICCDP was 7.32E-9, and the calculated ICLERP was 1. 75E-9. The staff finds the calculated ICCDP and ICLERP values are acceptable because the ICCDP and ICLERP values were less than the acceptance guidelines in RG 1.177 of 1E-6 for ICCDP and 1E-7 for ICLERP.

For Salem, Unit No. 2, the NRC staff finds that given that the total baseline for CDF was 4.02E-5/year, and the calculated .:1CDF was 6.34E-8/year, the risk metric for .:1CDF satisfies the RG 1.174 acceptance guidelines and is considered to be a "very small" change in risk. The staff also finds that given that the total baseline LERF was 4.42E-7/year, and the calculated .:1LERF was 9.37E-10/year, the risk metric for .:1LERF satisfies the RG 1.174 acceptance guidelines and is considered to be a "very small" change in risk. The calculated ICCDP was 3.68E-9, and the calculated ICLERP was 8.04E-10. The staff finds the calculated ICCDP and ICLERP values are acceptable because the ICCDP and ICLERP values are less than the acceptance guidelines in RG 1.177 of 1E-6 for ICCDP and 1E-7 for ICLERP.

3.2.2 Tier 2: Avoidance of Risk-Significant Plant Configurations The second tier evaluates that the licensee places appropriate restrictions such that risk-significant plant equipment outage configurations will not occur when equipment associated with the proposed CT is implemented. The licensee should provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is taken out of service in accordance with the proposed TS change.

In LAR Attachment 1, Sections 4.2.1 and 4.2.2, the licensee provided Tier 2 restrictions for implementation of WCAP-14333 and WCAP-15376, respectively. The licensee also evaluated for concurrent component outage configurations and confirmed the applicability of the Tier 2 restrictions for Salem. The licensee stated that entry into these conditions is not typical and is entered due to equipment failure. In the event of an emergent condition during the extended CT, the licensee will use its Tier 3 CRMP to assess the emergent condition and direct activities to restore the logic train to exit the action statement or fully implement the Tier 2 restrictions.

The NRC staff reviewed these restrictions and found they are consistent with the Tier 2 restrictions identified in the NRC staffs SE on WCAP-14333 and WCAP-15376.

From the given restrictions, the licensee evaluated concurrent component outage configurations and confirmed the applicability of Tier 2 restrictions to Salem. The NRC staff finds the provided Tier 2 restrictions are appropriate and provide reasonable assurance that risk-significant plant equipment outage configurations will not occur, based on the fact that the Tier 2 restrictions satisfy the conditions in the NRC staff's SEs for WCAP-14333 and WCAP-15376.

3.2.3 Tier 3: Risk-Informed Plant Configuration and Control Management Based on RG 1.177, the CRMP provides a proceduralized risk-informed assessment to manage the risk associated with equipment inoperability. The CRMP tool utilizes at least a Level 1 at-power internal events PRA model. The CRMP assessment may use any combination of quantitative and qualitative input.

In LAR Attachment 1, Section 4.3. 7, the licensee stated that Salem utilizes the Equipment out of Service (EOOS) Configuration Risk Monitor program as its CRMP tool, which uses the same fault trees and database as the internal events PRA model, so it is fully capable of evaluating CDF and LERF for internal events. Salem's CRMP has the capability to perform a configuration-dependent assessment of the overall impact on risk of proposed plant configurations prior to, and during, the performance of maintenance activities that remove equipment from service with the EOOS tool. Salem also reassesses risk if an equipment failure, malfunction, or emergent condition produces a plant configuration that has not been previously assessed. The licensee further states the EOOS tool is procedurally controlled and produces quantitative risk insights and qualitative defense-in-depth considerations.

The NRC staff finds that the licensee's program to control risk is capable of adequately assessing the activities being performed to ensure that high-risk plant configurations do not occur and/or compensatory actions are implemented if a high-risk plant configuration or condition should occur. As such, the licensee's program provides for the assessment and management of increased risk during maintenance activities as required by the Maintenance Rule at 10 CFR 50.65(a)(4), and satisfies the RG 1.177 guidance for a CRMP for the proposed TS change.

3.2.4 Addressing WCAP-14333 and WCAP-15376 Conditions and Limitations 3.2.4.1 Limitations for WCAP-14333 The evaluation of the two NRC staff SE conditions and limitations of WCAP-14333 is discussed below.

WCAP-14333 SE Condition 1 Condition 1 of the SE for WCAP-14333 is for the licensee to confirm the applicability of WCAP-14333-P analysis for the plant.

WCAP-14333 and WCAP-15376 provide a generic PRA model for the evaluation of the CT and bypass test times. The NRC staff found this generic model and the WCAP-14333 and WCAP-15376 evaluations to be acceptable on a generic basis in their SEs dated July 13, 1998, and December 20, 2002, respectively. Although the SEs accepted the use of a representative model as generally reasonable, the application of the representative model and the associated results to a specific plant introduce a degree of uncertainty because of modeling, design, and operational differences. Therefore, each licensee adopting WCAP-14333 needs to confirm that the TR analyses and results are applicable to its plant.

To determine that WCAP-14333 is applicable to Salem, the licensee addressed the implementation guidance developed by the PWROG in LAR Attachment 1, Section 4.2.1, Tables 4-1, 4-2, and 4-3. These tables compare plant-specific data to the generic analysis assumptions. The evaluation provided by the licensee compared the analysis assumptions in

WCAP-14333 to plant-specific parameters, including surveillance and maintenance intervals, operator actions, transient and anticipated transient without scram (AlWS) frequencies, actuation signals, safety functions, and certain component failure probabilities. Based on the above discussion and the NRC staff's Tier 1 evaluation in this SE, the staff finds the evaluation provided by the licensee confirms that the generic evaluation assumptions used in the WCAPs are applicable to Salem. Therefore, the staff finds that SE Condition 1 is satisfied.

WCAP-14333 SE Condition 2 Condition 2 of the SE for WCAP-14333 is for the licensee to address the Tier 2 and Tier 3 analyses, including the CRMP insights, which confirm that these insights are incorporated into the decisionmaking process before taking equipment out of service.

Based on the NRC staff's Tier 2 and Tier 3 evaluation in Sections 3.2.2.2 and 3.2.2.3 of this SE, respectively, the staff finds that SE Condition 2 is satisfied.

3.2.4.2 Limitations for WCAP-15376 The evaluation of the five NRC staff SE conditions and limitations of WCAP-15376 is discussed below.

WCAP-15376 SE Condition 1 Condition 1 of the SE for WCAP-15376 is that the licensee is expected to confirm the applicability of the TR to its plant, and to perform a plant-specific assessment of containment failures and address any design or performance differences that may affect the proposed changes.

To determine that WCAP-15376 is applicable to Salem, the licensee addressed the implementation guidance developed by PWROG in LAR Attachment 1, Section 4.2.2, Tables 4-4, 4-5, and 4-6. These tables compare plant-specific data to the generic analysis assumptions. The evaluation provided by the licensee compared the analysis assumptions in WCAP-15376 to plant-specific parameters, including surveillance and maintenance intervals, operator actions, transient and AlWS frequencies, actuation signals, safety functions, and certain component failure probabilities. The licensee also demonstrated that the current baseline CDF and LERF values for Salem meet RG 1.174 criteria for determining that small increases in CDF and LERF are acceptable. The licensee also quantitatively demonstrated the AlWS contribution to CDF, which indicates the licensee understands the importance of AlWS events to the plant risk at Salem. Based on the above discussion and the NRC staff's Tier 1 evaluation in this SE, the staff finds the evaluation provided by the licensee confirms that the generic evaluation assumptions used in the WCAPs are applicable to Salem. The staff finds the first part of SE Condition 1 is satisfied.

The second part of Condition 1 requires plant-specific assessment of containment failures and addressing any design or performance differences that may affect the proposed changes.

WCAP-15376 was based on a large dry containment and assumed that the only contributions to LERF would come from containment bypass events and core damage events with the containment not isolated. The licensee stated in LAR Attachment 1, Section 4.2.2, that Salem has a large dry containment and that typical containment failure modes at Salem include containment bypass events and containment isolation failure. The NRC staff evaluated the accidents provided by the licensee that would likely cause containment failure based on

containment bypass and containment isolation failure, and the staff finds these accidents are typical of a large, dry containment. In addition, based on the staff Tier 1 evaluation in Section 3.2.2.1 of this SE, the NRC staff finds the licensee's PRA model to be technically adequate to analyze containment failures, and the licensee's containment assessment conclusions are acceptable. Therefore, the NRC staff finds the licensee's containment failure assessment to be consistent with WCAP-15376. The NRC staff finds that the second part of SE Condition 1 is satisfied.

WCAP-15376 SE Condition 2 Condition 2 of the SE for WCAP-15376 is for the licensee to address the Tier 2 and Tier 3 analyses, including risk-significant configuration insights and confirm that these insights are incorporated into the plant-specific CRMP.

Based on the NRC staff Tier 2 and Tier 3 evaluation in Sections 3.2.2.2 and 3.2.2.3 of this SE, respectively, the staff finds that SE Condition 2 is satisfied.

WCAP-15376 SE Condition 3 Condition 3 of the SE for WCAP-15376 is that the risk impact of concurrent testing of one logic cabinet and associated RTB needs to be evaluated on a plant-specific basis to ensure conformance with the WCAP-15376 evaluation, and RG 1.174 and RG 1.177.

WCAP-15376 did not specifically evaluate or preclude concurrent testing of one logic cabinet and its associated RTB. Based on this, the NRC staff questioned the applicability of the TR to this particular maintenance configuration. In response to the NRC staff's RAls on WCAP-15376, the PWROG provided risk estimates for a more limiting configuration of a 30-hour maintenance time. The ICCDP and ICLERP estimates in the PWROG risk estimates were within the guidelines of RG 1.177. However, the licensee proposes to bypass one logic cabinet and its associated RTB for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Since the incremental risk metrics are met when the logic cabinet and its associated RTB are unavailable during a 30-hour out-of-service maintenance time, they are also met when the logic cabinet and its associated RTB is unavailable during a 4-hour bypass time. The NRC staff finds the generic analysis presented in WCAP-15376 for concurrent testing of one logic cabinet and associated RTB is applicable to Salem. The staff also finds that the risk metrics are expected to be within the acceptance guidelines in RG 1.177 for this configuration, and therefore, the staff finds that SE Condition 3 is satisfied.

WCAP-15376 SE Condition 4 Condition 4 of the SE for WCAP-15376 is that in order for the licensee to ensure consistency with the referenced plant, the model assumptions for human reliability in WCAP-15376 should be confirmed to be applicable to the plant-specific configuration.

In LAR Attachment 1, Section 4.2.2, Table 4-7, the licensee lists the operator actions credited in the WCAP-15376 analysis. It indicates if the operators have sufficient time and if procedures are in place, the operators will be directed to perform the operator actions listed in Section 4.2.2, Table 4-7. In Table 4.7, the licensee concluded that the human reliability associated with the relevant operator actions in the TR are applicable to Salem based on a plant-specific assessment and confirmed that sufficient time is available for operator actions, and that the procedures for manual actions are in place for each of the operator action categories. The NRC staff reviewed the operator actions provided in Table 4-7 and finds the actions to be acceptable

and consistent with WCAP-15376, and that the WCAP-15376 model assumptions are, therefore, applicable to Salem. The staff finds that Condition 4 of the SE is satisfied because the licensee confirmed the operator actions that are credited have sufficient time, and procedures are in place for the operator actions.

WCAP-15376 SE Condition 5 Condition 5 of the SE for WCAP-15376 is that for future digital upgrades with increased scope, integration, and architectural differences beyond that of Eagle 21, the NRC staff finds the generic applicability of WCAP-15376 to future digital systems is not clear and should be considered on a plant-specific basis.

As stated in its LAR, this condition does not apply to the current Salem LAR and is not approved for future digital upgrades.

3.2.5 Plant-Specific Evaluations for Functions Not Evaluated Generically This section provides justification for the TS changes proposed that were not included in the generic analyses approved in WCAP-10271, as supplemented; WCAP-14333; orWCAP-15376.

With regard to plant-specific evaluations for functions not evaluated generically, TSTF-418, Section 4, provides the following guidance:

In order to apply the various relaxations justified in WCAP-10271 and WCAP-14333 to plant specific Functions not evaluated generically, a plant specific evaluation of those Functions and any additional plant specific Functions not listed in NUREG-1431 Rev. 1 but contained in the plant specific SSPS or RPS design must be performed.

WCAP-14333 did not evaluate RTS Function 20 (Reactor Coolant Pump Breaker Position Trip (above P7)); therefore, the licensee performed a plant-specific analysis for its proposed CT extension. In LAR Section 4.3.4.2, the licensee provided a bounding calculation to demonstrate the risk impact due to the change in unavailability of RTS Function 20 is negligible. The NRC staff reviewed the bounding calculation and finds the risk impact due to the change in unavailability of RTS Function 20 is negligible. Therefore, the staff finds the plant-specific analysis for RTS Function 20 is acceptable, and the proposed CT extension for RTS Function 20 is acceptable.

In addition, WCAP-14333 did not evaluate ESFAS Function 3.c.2 (Containment Ventilation Isolation, Automatic Actuation Logic), Function 6 (Safeguards Equipment Control System),

Function 7.a (Vital Bus Undervoltage, Loss of Voltage), Function 7.b (Vital Bus Undervoltage, Sustained Degraded Voltage), Function 9.a (Semiautomatic Transfer to Recirculation, RWST Level Low), and Function 9.b (Semiautomatic Transfer to Recirculation, Automatic Isolation Logic). In LAR Section 4.3.1.5, the licensee described the PRA modeling for Functions 7.a, 7.b, 9.a, and 9.b. The NRC staff finds that the level of detail in the licensee's PRA model for Functions 7.a, 7.b, 9.a, and 9.b is adequate for the application because it is consistent with the level of detail in the PRA model evaluated for these functions in WCAP-14333. In RAI 1 by letter dated June 20, 2018, the NRC staff requested that the licensee provide a plant-specific analysis for Functions 3.c.2 and 6, since these analyses were not found in the LAR. In response to RAI 1 by letter dated July 17, 2018, the licensee described how its current PRA model of record already models Functions 3.c.2 and 6, and that its current PRA model of record uses industry and plant-specific unavailability event data for these functions. The NRC staff

finds that the PRA modeling and plant-specific analyses for Functions 3.c.2 and 6 is adequate for this application because it is consistent with the level of detail in the PRA model evaluated for functions in WCAP-14333. Therefore, based on the above discussion, the staff concludes the proposed extension for the CT for ESFAS Functions 3.c.2, 6, 7.a, 7.b, 9.a, and 9.b is acceptable.

3.2.6 Risk Evaluation (Key Principle 4) Conclusions The licensee has demonstrated the technical acceptability and scope of its PRA model, and the PRA model can support implementation of WCAP-14333 and WCAP-15376. The risk metrics satisfy the acceptance guidelines in RG 1.174 and RG 1.177. The licensee has appropriate restrictions in place to provide reasonable assurance that risk-significant configurations will be prevented and avoided. The licensee also has a CRMP that is administratively controlled through plant procedures and training. For functions that are not generically evaluated in WCAP-14333 and WCAP-15376, the licensee has provided an acceptable plant-specific evaluation for these functions per the guidelines in WCAP-14333 and WCAP-15376. Salem satisfies the RG 1.174 and RG 1.177 guidelines for the risk evaluation for the proposed change, and therefore, the NRC staff finds that Key Principle 4 is met.

3.3 Implementation and Monitoring Program (Key Principle 5)

RG 1.174 and RG 1.177 also establish the need for an implementation and monitoring program to ensure that extensions to TS CTs and bypass test times do not degrade operational safety over time and that no adverse effects occur from unanticipated degradation or increases in common cause mechanisms. The purpose of an implementation and monitoring program is to ensure that the impact of the proposed TS change continues to reflect the reliability and availability of SSCs impacted by the change. In addition, the application of the three-tiered approach in evaluating the extensions to CTs and bypass test times provides additional assurance that the changes will not significantly impact the key principle of defense in depth.

The licensee monitors the reliability and availability of the RTS and ESFAS instrumentation under the Maintenance Rule (10 CFR 50.65), which requires a licensee to monitor the performance or condition of SSCs against licensee-established goals. Salem satisfies the RG 1.174 and RG 1.177 guidelines for an implementation and monitoring program for the proposed change, and therefore, the NRC staff finds that Key Principle 5 is met.

3.4 Conclusion The NRC staff finds that the licensee has demonstrated the applicability of WCAP-14333 and WCAP-15376 to Salem and has met the limitations and conditions as outlined in the NRC staff's safety evaluation reports. The staff finds the plant-specific analysis is acceptable for the signals not evaluated in the TRs. The Tier 1 conditions were found to be acceptable, and the estimates for ~CDF, ~LERF, ICCDP, and ICLERP were found to be within the acceptance guidelines of RG 1.174 and RG 1.177. The licensee's Tier 2 analysis evaluated concurrent outage configurations and confirmed the applicability of the risk-significant configurations identified by the WCAP-14333 and WCAP-15376 safety evaluation report limitations and conditions and TR analysis to ensure control of these configurations. The licensee's Tier 3 CRMP at Salem was found to be consistent with the CRMP guidance in RG 1.177 and the Maintenance Rule (10 CFR 50.65(a)(4)) for the implementation of WCAP-14333 and WCAP-15376. The licensee monitors the reliability and availability of the RTS and ESFAS instrumentation under the Maintenance Rule (10 CFR 50.65(a)(1)). The NRC staff concludes that the TS revisions

proposed by the licensee are consistent with the CTs and bypass test times approved for WCAP-14333 and WCAP-15376 and meet the staff's safety evaluation report conditions and limitations forWCAP-14333 and WCAP-15376.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the New Jersey State official was notified of the proposed issuance of the amendments on April 4, 2018. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change requirements with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (83 FR 10921; March 13, 2018). Accordingly, the 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 the 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 Commission's 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.

Principal Contributors: B. Hartle G. Singh Date: December 19, 2018

ML18318A266 *by memorandum **by e-mail OFFICE NRR/DORL/LPL 1/PM NRR/DORL/LPL 1/LA NRR/DRA/APLA/BC* NRR/DE/EICB/BC*

NAME JKim PTalukdar/LRonewicz SRosenberg MWaters DATE 11/27/2018 11/22/2018 10/25/2018 11/13/2018 OFFICE NRR/DSS/STSB/BC OGC-NLO** NRR/DORL/LPL 1/BC NRR/DORL/LPL 1/PM NAME VCusumano KGamin JDanna JKim DATE 11/28/2018 12/18/2018 12/19/2018 12/19/2018

v t e Letter Sequence Approval
EPID:L-2017-LLA-0442, License Amendment Request for Implementation of WCAP-14333 and WCAP-15376, Reactor Trip System Instrumentation and Engineered Safety Feature Actuation System Instrumentation Test Times and Completion Times (Approved, Closed)
Initiation Request Acceptance, Acceptance Supplement Administration Questions Answers 17 July 2018 Results Approval Other:
MONTHYEAR2018-12-19 [Table View]

ML18318A266

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SUBJECT:

Dear Mr. Sena:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

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