Text

Issuance of Amendment Nos. 226 and 214 Adoption of TSTF-425, Revision 3, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5B
	ML19045A480
Person / Time
Site:	Prairie Island
Issue date:	04/16/2019
From:	Robert Kuntz; Plant Licensing Branch III
To:	Sharp S; Northern States Power Co
	Kuntz R
References
	EPID L-2018-LLA-0065
	Download: ML19045A480 (133)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 Mr. Scott Sharp Site Vice President April 16, 2019 Prairie Island Nuclear Generating Plant Northern States Power Company - Minnesota 1717 Wakonade Drive East Welch, MN 55089

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 -

ISSUANCE OF AMENDMENTS RE: ADOPTION OF TSTF-425, REVISION 3, RELOCATE SURVEILLANCE FREQUENCIES TO LICENSEE CONTROL-RITSTF INITIATIVE 58 (EPID: L-2018-LLA-0065)

Dear Mr. Sharp:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 226 to Renewed Facility Operating License No. DPR-42 and Amendment No. 214 to Renewed Facility Operating License No. DPR-60 for the Prairie Island Nuclear Generating Plant, Units 1 and 2, respectively. The amendments consist of changes to the technical specifications (TSs) in response to your application dated March 15, 2018, as supplemented by letter dated September 17, 2018.

The amendments revise the TSs to adopt Technical Specifications Task Force (TSTF) Standard Technical Specifications (STS) Change Traveler TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control-RITSTF [Risk-Informed TSTF] Initiative 5b."

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

Docket Nos. 50-282 and 50-306

Enclosures:

1. Amendment No. 226 to DPR-42

2. Amendment No. 214 to DPR-60

3. Safety Evaluation cc: Listserv Robert F. Kuntz, Senior Project Manager Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 NORTHERN STATES POWER COMPANY-MINNESOTA DOCKET NO. 50-282 PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 226 License No. DPR-42

1.

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

A.

The application for amendment by Northern States Power Company, a Minnesota Corporation (NSPM, the licensee), dated March 15, 2018, as supplemented by letter dated September 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; 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.

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-42 is hereby amended to read as follows:

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 226, are hereby incorporated in the renewed operating license.

NSPM shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of the date of its issuance and shall be implemented within 120 days.

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications FOR THE NUCLEAR REGULATORY COMMISSION DQJ~, 2iefo/ ---

Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: April 16, 201 9

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 NORTHERN STATES POWER COMPANY-MINNESOTA DOCKET NO. 50-306 PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 214 License No. DPR-60

1.

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

A.

The application for amendment by Northern States Power Company, a Minnesota Corporation (NSPM, the licensee), dated March 15, 2018, as supplemented by letter dated September 18, 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; 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.

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-60 is hereby amended to read as follows:

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 214, are hereby incorporated in the renewed operating license.

NSPM shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of the date of its issuance and shall be implemented within 120 days.

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications FOR THE NUCLEAR REGULATORY COMMISSION

{2<dChq, ~~

Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: Apr i 1 1 6, 2 o 1 9

(3) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, NSPM to receive, possess, and use at any time any byproduct, source and 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; (4) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, NSPM 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 and equipment calibration or associated with radioactive apparatus or components; (5) Pursuant to the Act and 10 CFR Parts 30 and 70, NSPM to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility; (6) Pursuant to the Act and 10 CFR Parts 30 and 70, NSPM to transfer byproduct materials from other job sites owned by NSPM for the purpose of volume reduction and decontamination.

C.

This renewed operating 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, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; 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 NSPM is authorized to operate the facility at steady state reactor core power levels not in excess of 1677 megawatts thermal.

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 226, are hereby incorporated in the renewed operating license. NSPM shall operate the facility in accordance with the Technical Specifications.

(3) Physical Protection NSPM shall fully implement and maintain in effect all provisions of the Commission-approved physical security, guard training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains Renewed Operating License No. DPR-42 Amendment No. 226 (3) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, NSPM to receive, possess, and use at any time any byproduct, source and 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;

( 4) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, NSPM 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 and equipment calibration or associated with radioactive apparatus or components; (5) Pursuant to the Act and 10 CFR Parts 30 and 70, NSPM to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility; (6) Pursuant to the Act and 10 CFR Parts 30 and 70, NSPM to transfer byproduct materials from other job sites owned by NSPM for the purposes of volume reduction and decontamination.

C.

This renewed operating 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, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; 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 NSPM is authorized to operate the facility at steady state reactor core power levels not in excess of 1677 megawatts thermal.

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 214, are hereby incorporated in the renewed operating license.

NSPM shall operate the facility in accordance with the Technical Specifications.

(3) Physical Protection NSPM shall fully implement and maintain in effect all provisions of the Commission-approved physical security, guard training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains Renewed Operating License No. DPR-60 Amendment No. 214

Definitions 1.1 1.1 Definitions ( continued)

SHUTDOWN MARGIN (SDM)

SLAVE RELAY TEST THERMAL POWER TRIP ACTUATING DEVICE OPERATIONAL TEST (TADOT)

Prairie Island Units 1 and 2 SDM shall be the instantaneous amount ofreactivity by which:

a.

The reactor is subcritical; or

b.

The reactor would be subcritical from its present condition assuming all rod cluster control assemblies (RCCAs) are fully inserted except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn. With any RCCA not capable of being fully inserted, the reactivity worth of the RCCA must be accounted for in the determination of SDM. In MODES 1 and 2, the fuel and moderator temperatures are changed to the nominal zero power design temperature.

A SLAVE RELAY TEST shall consist of energizing all slave relays in the channel required for channel OPERABILITY and verifying the OPERABILITY of each required slave relay. The SLAVE shall include a continuity check of associated required testable actuation devices. The SLAVE RELAY TEST may be performed by means of any series of sequential, overlappping, or total steps.

THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.

A T ADOT shall consist of operating the trip actuating device and verifying the OPERABILITY of all devices in the channel required for trip actuating device OPERABILITY. The TADOT shall include adjustment, as necessary, of the trip actuating device so that it actuates at the required setpoint within the necessary accuracy. The T ADOT may be performed by means of any series of sequential, overlapping, or total channel steps.

1.1-6 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

MODE TITLE 1

Power Operation 2

Startup 3

Hot Standby 4

Hot Shutdown<b) 5 Cold Shutdown<b) 6 Refueling< c >

(a)

Excluding decay heat.

Table 1.1-1 (page 1 of 1)

MODES REACTIVITY

%RATED CONDITION THERMAL (keff)

POWER<a)

0.99

>5

0.99

<5

<0.99 NA

<0.99 NA NA NA Definitions 1.1 AVERAGE REACTOR COOLANT TEMPERATURE (Of)

NA NA

350 350 > Tavg > 200

<200 NA (b)

All reactor vessel head closure bolts fully tensioned.

( c)

One or more reactor vessel head closure bolts less than fully tensioned.

Prairie Island Units 1 and 2 1.1-7 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SR Applicability 3.0 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY SR 3.0.1 SR 3.0.2 Prairie Island Units 1 and 2 SRs shall be met during the MODES or other specified conditions in the Applicability for individual LCOs, unless otherwise stated in the SR. Failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the LCO.

Failure to perform a Surveillance within the specified Frequency shall be failure to meet the LCO except as provided in SR 3.0.3.

Surveillances do not have to be performed on inoperable equipment or variables outside specified limits.

The specified Frequency for each SR is met, if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.

For Frequencies specified as "once," the above interval extension does not apply.

If a Completion Time requires periodic performance on a "once per... " basis, the above Frequency extension applies to each performance after the initial performance.

Exceptions to this Specification are stated in the individual Specifications.

3.0-5 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

3.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM)

SDM 3.1.1 LCO 3.1.1 SDM shall be within the limits provided in the COLR APPLICABILITY:

MODE 2 with keff< 1.0, MODES 3, 4, and 5.

ACTIONS CONDITION A. SDM not within limit.

REQUIRED ACTION A.1 Initiate boration to restore SDM to within limit.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.1.1.1 Verify SDM is within limits.

COMPLETION TIME 15 minutes FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.1.1-1 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.1.2.1 Verify measured core reactivity is within+/- 1 % 8k/k of predicted values.

SR 3.1.2.2

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

1. Only required to be performed after 60 effective full power days (EFPD).

2. The predicted reactivity values may be adjusted (normalized) to correspond to the measured core reactivity prior to exceeding a fuel bumup of 60 EFPD after each fuel loading.

Verify measured core reactivity is within +/- 1 % 8k/k of predicted values.

Core Reactivity 3.1.2 FREQUENCY Prior to entering MODE 1 after each refueling In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.1.2-2 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

Rod Group Alignment Limits 3.1.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.1.4.1 Verify individual rod positions within alignment limit.

SR 3.1.4.2 SR 3.1.4.3 Verify rod freedom of movement (trippability) by moving each rod, not fully inserted in the core, 2: 10 steps in either direction.

Verify rod drop time of each rod, from the fully withdrawn position, is.:::: 1.8 seconds from the beginning of decay of stationary gripper coil voltage to dashpot entry, with:

a. Tavg 2: 500°F; and

b. Both reactor coolant pumps operating.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prior to reactor criticality after each removal of the reactor head Prairie Island Units 1 and 2 3.1.4-4 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

ACTIONS ( continued)

Shutdown Bank Insertion Limits 3.1.5 CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

SURVEILLANCE RE UIREMENTS SURVEILLANCE 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months FREQUENCY SR 3.1.5.1 Verify each shutdown bank is within the limits specified in the COLR.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.1.5-2 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

Control Bank Insertion Limits 3.1.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.1.6.1 Verify estimated critical control bank position is within the limits specified in the COLR.

SR 3.1.6.2 Verify each control bank insertion is within the limits specified in the COLR.

SR 3.1.6.3 Verify sequence and overlap limits specified in the COLR are met for control banks not fully withdrawn from the core.

FREQUENCY Prior to achieving criticality In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units I and 2 3.1.6-3 Unit I - Amendment No. 226 Unit 2-Amendment No. 214

PHYSICS TESTS Exceptions - MODE 2 3.1.8 ACTIONS (continued)

CONDITION REQUIRED ACTION B. THERMAL POWER not B.1 Open reactor trip breakers.

within limit.

C. RCS lowest loop average C.1 Restore RCS lowest loop temperature not within average temperature to limit.

within limit.

D. Required Action and D.l Bein MODE 3.

associated Completion Time of Condition C not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.1.8.1 Perform a CHANNEL OPERATIONAL TEST on power range and intermediate range channels per SR 3.3.1.7, SR 3.3.1.8, and Table 3.3.1-1.

SR 3.1.8.2 Verify the RCS lowest loop average temperature is

~ 535°F.

COMPLETION TIME Immediately 15 minutes 15 minutes FREQUENCY Prior to initiation of PHYSICS TESTS In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.1.8-2 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

PHYSICS TESTS Exceptions - MODE 2 3.1.8 SURVEILLANCE REQUIREMENTS ( continued)

SURVEILLANCE SR 3.1.8.3 Verify THERMAL POWER is::: 5% RTP.

FREQUENCY In accordance with the Surveillance Frequency Control Program SR 3.1.8.4 Verify SOM is within the limits provided in the COLR.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.1.8-3 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS F 0 (Z) 3.2.1

N()TE--------------------------------------------------

During power escalation at the beginning of each cycle, THERMAL P()WER may be increased until an equilibrium power level has been achieved, at which a power distribution measurement is obtained.

SURVEILLANCE SR 3.2.1.1 Verify Fg(Z) is within limit.

Prairie Island Units 1 and 2 3.2.1-4 FREQUENCY

()nee after each refueling prior to THERMAL P()WER exceeding 75% RTP

()nee within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after achieving equilibrium conditions after exceeding, by

10% RTP, the THERMAL P()WERat which F g (Z) was last verified In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE RE UIREMENTS SR 3.2.1.2 (continued)

Prairie Island Units 1 and 2 SURVEILLANCE 3.2.1-6 F 0 (Z) 3.2.1 FREQUENCY Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after achieving equilibrium conditions after exceeding, by

10% RTP, the THERMAL POWER at which F;(Z) was last verified In accordance with the Surveillance Frequency Control Program Unit 1 -Amendment No. 226 Unit 2-Amendment No. 214

3.2.2 SURVEILLANCE RE UIREMENTS SURVEILLANCE FREQUENCY SR 3.2.2.1 Verify F~ is within limits specified in the COLR.

Once after each refueling prior to THERMAL POWER exceeding 75%RTP Prairie Island Units 1 and 2 3.2.2-3 In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

3.2 POWER DISTRIBUTION LIMITS 3.2.3 AXIAL FLUX DIFFERENCE (AFD)

AFD 3.2.3 LCO 3.2.3 The AFD in% flux difference units shall be maintained within the limits specified in the COLR.

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

The AFD shall be considered outside limits when two or more OPERABLE excore channels indicate AFD to be outside limits.

APPUCABILIIY:

MODE 1 with THERMAL POWER~ 50% RTP.

ACTIONS CONDITION A. AFD not within limits.

REQUIRED ACTION A.1 Reduce THERMAL POWER to< 50% RTP.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.2.3.1 Verify AFD within limits for each OPERABLE excore channel.

COMPLETION TIME 30 minutes FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.2.3-1 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.2. 4.1 -------------------------NOTES------------------------------

1.

With input from one Power Range Neutron Flux channel inoperable and THERMAL POWER

85% RTP, the remaining three power range channels can be used for calculating QPTR.

2.

SR 3.2.4.2 may be performed in lieu of this Surveillance.

Verify QPTR is within limit by calculation.

SR 3.2.4.2 --------------------------NOTE------------------------------

N ot required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after input from one or more Power Range Neutron Flux channels are inoperable with THERMAL POWER

> 85% RTP.

Verify QPTR is within limit using core power distribution measurement information.

QPTR 3.2.4 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.2.4-5 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS

N()TE--------------------------------------------------

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

SURVEILLANCE SR 3.3.1.1 Perform CHANNEL CHECK.

SR 3.3.1.2 -------------------------- N()TES----------------------------

1.

Adjust NIS channel if absolute difference is

>2%.

2.

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL P()WER is~ 15% RTP.

Compare results of calorimetric heat balance calculation to Nuclear Instrumentation System (NIS) channel output.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.1-10 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3. 3.1.3

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

1.

Adjust NIS channel if absolute difference is

~2%.

2.

Not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after THERMAL POWER is~ 15% RTP.

Compare results of the core power distribution measurements to NIS AFD.

SR 3.3.1.4 ----------------------------NOTE---------------------------

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

Perform TADOT.

SR 3.3.1.5 Perform ACTUATION LOGIC TEST.

R TS Instrumentation 3.3.1 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.1-11 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS ( continued)

SURVEILLANCE SR 3.3.1.6 ----------------------------N()TE----------------------------

N ot required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL P()WER is 2: 75% RTP.

Calibrate excore channels to agree with core power distribution measurements.

SR 3. 3.1. 7

N ()TE----------------------------

N ot required to be performed for source range instrumentation prior to entering M()DE 3 from M()DE 2 until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after entry into M()DE 3.

Perform C()T.

RTS Instrumentation 3.3.1 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.1-12 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE RE UIREMENTS continued SURVEILLANCE SR 3.3.1.8

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

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

2. Not required to be performed for intermediate and source range instrumentation prior to reactor startup following shutdown ::: 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

Perform COT.

RTS Instrumentation 3.3.1 FREQUENCY

NOTE-------

Only required when not performed within the Frequency specified in the Surveillance Frequency Control Program Prior to reactor startup Twelve hours after reducing power below P-10 for power and intermediate range instrumentation AND Four hours after reducing power below P-6 for source range instrumentation In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.1-13 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3. 3.1. 9

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

V erification of setpoint is not required.

Perform TADOT.

SR 3.3.1.10 ---------------------------NOTE-----------------------------

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

Perform CHANNEL CALIBRATION.

SR 3.3.1.11 --------------------------NOTE------------------------------

N eutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

RTS Instrumentation 3.3.1 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.1-14 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3.3.1.12 ----------------------------NOTE----------------------------

This Surveillance shall include verification of Reactor Coolant System resistance temperature detector bypass loop flow rate.

Perform CHANNEL CALIBRATION.

SR 3.3.1.13 Perform COT.

SR 3. 3.1.14 ----------------------------NOTE----------------------------

V erification of setpoint is not required.

Perform TADOT.

RTS Instrumentation 3.3.1 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.1-15 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

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

Verification of setpoint is not required.

Perform TADOT.

SR 3. 3.1.16 ----------------------------NOTE----------------------------

N eutron detectors are excluded from response time testing.

Verify RTS RESPONSE TIME is within limits.

RTS Instrumentation 3.3.1 FREQUENCY Prior to exceeding the P-9 interlock whenever the unit has been in MODE 3, if not performed within the previous 31 days In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.1-16 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

ESF AS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS

N()TE--------------------------------------------------

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

SURVEILLANCE SR 3.3.2.1 Perform CHANNEL CHECK.

SR 3.3.2.2 Perform ACTUATl()N L()GIC TEST.

SR 3.3.2.3 Perform C()T.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program SR 3.3.2. 4

N ()TE. ---------------------------

Prairie Island Units 1 and 2 Verification of setpoint not required.

Perform TAD()T.

3.3.2-7 In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE ESF AS Instrumentation 3.3.2 FREQUENCY SJl 3.3.2.5

N()TE----------------------------

V erification of setpoint not required.

Perform T AD()T.

SJl 3.3.2. 6

N ()TE----------------------------

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

Perform CHANNEL CALIB1lA Tl()N.

SJl 3.3.2.7 Perform MASTEJl RELAY TEST.

SJl 3.3.2.8 Perform SLAVE RELAY TEST.

In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.2-8 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

EM Instrumentation 3.3.3 SURVEILLANCE REQUIREMENTS

N()TE--------------------------------------------------

SR 3.3.3.1 and SR 3.3.3.2 apply to each EM instrumentation Function in Table 3.3.3-1.

SURVEILLANCE SR 3.3.3.1 Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.

SR 3.3.3.2

N ()TE----------------------------

N eutron detectors are excluded from CHANNEL CALIBRATI()N.

Perform CHANNEL CALIBRATl()N.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.3-5 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

4 kV Safeguards Bus Voltage Instrumentation 3.3.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.3.4.1 Perform COT on each undervoltage and degraded voltage channel.

SR 3.3.4.2 Perform ACTUATION LOGIC TEST on each automatic load sequencer.

SR 3.3.4.3 Perform CHANNEL CALIBRATION on undervoltage and degraded voltage channels with Allowable Value as follows:

a.

Undervoltage Allowable Value~ 3016 V and

~ 3224 V with an undervoltage time delay of 4 +/- 1.5 seconds.

b.

Degraded voltage Allowable Value~ 3944 V and

~ 4002 V with a degraded voltage time delay of 8 +/- 0.5 seconds and degraded voltage DG start time delay of 7.5 to 63 seconds.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.3.4-5 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

CRSVS Actuation Instrumentation 3.3.6 SURVEILLANCE REQUIREMENTS

.----------------------NC}TE--------------------------------------------------

Refer to Table 3.3.6-1 to determine which SRs apply for each CRSVS Actuation Function.

SURVEILLANCE SR 3.3.6.1 Perform CHANNEL CHECK.

SR 3.3.6.2 Perform C()T.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program SR 3.3.6.3

N()TE----------------------------

Verification of setpoint is not required.

Perform TAD()T.

SR 3.3.6.4 Perform CHANNEL CALIBRATI()N.

Prairie Island Units 1 and 2 3.3.6-3 In accordance with the Surveillance Frequency Control Program.

In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit2-AmendmentNo. 214

RCS Pressure, Temperature, and Flow - DNB Limits 3.4.1 ACTIONS (continued)

CONDITION REQUIRED ACTION B. Required Action and associated Completion Time not met.

B.1 Be in MODE 2.

SURVEILLANCE REQUIREMENTS SR 3.4.1.1 SR 3.4.1.2 SR 3.4.1.3 SURVEILLANCE Verify pressurizer pressure is greater than or equal to the limit specified in the COLR.

Verify RCS average temperature is less than or equal to the limit specified in the COLR.

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

Required to be performed within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after

~90% RTP.

Verify RCS total flow rate is within the limit specified in the COLR.

COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.1-2 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

RCS Minimum Temperature for Criticality 3.4.2 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.2 RCS Minimum Temperature for Criticality LCO 3.4.2 Each RCS loop average temperature (Tavg) shall be::'.:. 540°F.

APPLICABILITY:

MODE 1, MODE 2 with keff :::'.:. 1.0.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. T avg in one or more RCS A.1 Be in MODE 2 with loops not within limit.

keff < 1.0.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.4.2.1 Verify RCS Tavg in each loop:::_ 540°F.

Prairie Island Units 1 and 2 3.4.2-1 30 minutes FREQUENCY In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

ACTIONS ( continued)

CONDITION REQUIRED ACTION C. -----------NOTE-----------

C.1 Initiate action to restore Required Action C.2 parameter(s) to within shall be completed limits.

whenever this Condition is entered.

AND C.2 Determine RCS is Requirements of LCO acceptable for continued not met any time in other operation.

than MODE 1, 2, 3, or 4.

SURVEILLANCE RE UIREMENTS SR 3.4.3.1 SURVEILLANCE

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

Only required to be performed during RCS heatup and cooldown operations and RCS inservice leak and hydrostatic testing.

Verify RCS pressure, RCS temperature, and RCS heatup and cooldown rates are within the limits specified in the PTLR.

RCS PIT Limits 3.4.3 COMPLETION TIME Immediately Prior to entering MODE4 FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.3-2 Unit 1 -Amendment No. 226 Unit 2 -Amendment No. 214

3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.4 RCS Loops - MODES 1 and 2 RCS Loops - MODES 1 and 2 3.4.4 LCO 3.4.4 Two RCS loops shall be OPERABLE and in operation.

APPLICABILITY:

MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Requirements ofLCO not A.1 Be in MODE 3.

met.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.4.4.1 Verify each RCS loop is in operation.

Prairie Island Units 1 and 2 3.4.4-1 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months FREQUENCY In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

RCS Loops - MODE 3 3.4.5 SURVEILLANCE REQUIREMENTS SR 3.4.5.1 SR 3.4.5.2 SR 3.4.5.3 Prairie Island Units 1 and 2 SURVEILLANCE Verify required RCS loops are in operation.

Verify required steam generator capable of removing decay heat.

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

N ot required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a required pump is not in operation.

Verify correct breaker alignment and indicated power are available to each required pump.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program 3.4.5-4 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

RCS Loops - MODE 4 3.4.6 SURVEILLANCE REQUIREMENTS SR 3.4.6.1 SR 3.4.6.2 SR 3.4.6.3 SR 3.4.6.4 Prairie Island Units 1 and 2 SURVEILLANCE Verify required RHR or RCS loop is in operation.

Verify required SG capable of removing decay heat.

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

N ot required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a required pump is not in operation.

Verify correct breaker alignment and indicated power are available to each required pump.

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

N ot required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 4.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Verify required RHR loop locations susceptible to In accordance with gas accumulation are sufficiently filled with water. the Surveillance Frequency Control Program 3.4.6-3 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

RCS Loops -MODE 5, Loops Filled 3.4.7 SURVEILLANCE REQUIREMENTS SR 3.4.7.1 SR 3.4.7.2 SR 3.4.7.3 SR 3.4.7.4 Prairie Island Units 1 and 2 SURVEILLANCE Verify required RHR loop is in operation.

Verify required SG capable of removing decay heat.

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

N ot required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a required pump is not in operation.

Verify correct breaker alignment and indicated power are available to each required RHR pump.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Verify required RHR loop locations susceptible to In accordance with gas accumulation are sufficiently filled with the Surveillance water.

3.4.7-4 Frequency Control Program Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

RCS Loops - MODE 5, Loops Not Filled 3.4.8 SURVEILLANCE REQUIREMENTS SR 3.4.8.1 SR 3.4.8.2 SR 3.4.8.3 Prairie Island Units 1 and 2 SURVEILLANCE Verify required RHR loop is in operation.

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

N ot required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a required pump is not in operation.

Verify correct breaker alignment and indicated power are available to each required RHR pump.

Verify RHR loop locations susceptible to gas accumulation are sufficiently filled with water.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program 3.4.8-3 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

ACTIONS ( continued)

CONDITION REQUIRED ACTION B.

One group of pressurizer B.1 Restore group of pressurizer heaters inoperable.

heaters to OPERABLE status.

C.

Required Action and C.1 Be in MODE 3.

associated Completion Time of Condition B AND not met.

C.2 Be in MODE 4.

SURVEILLANCE REQUIREMENTS SR 3.4.9.1 SR 3.4.9.2 SR 3.4.9.3 SURVEILLANCE Verify pressurizer water level is.::: 90%.

Verify capacity of each required group of pressurizer heaters is::::. 100 kW.

Verify required pressurizer heaters are capable of being powered from an emergency power supply.

Pressurizer 3.4.9 COMPLETION TIME 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 6 hours 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units I and 2 3.4.9-2 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

ACTIONS ( continued)

CONDITION REQUIRED ACTION G.

Required Action and G.1 Be in MODE 3.

associated Completion Time of Condition F not AND met.

G.2 Be in MODE 4.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3. 4.11.1

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

1. Not required to be performed with block valve closed in accordance with the Required Actions of this LCO.

2. Only required to be performed in MODES 1 and 2.

Perform a complete cycle of each block valve.

SR 3. 4.11.2

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

Only required to be performed in MODES 1 and 2.

Perform a complete cycle of each PORV.

Pressurizer PORV s 3.4.11 COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.11-4 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

L TOP - RCSCL T > SI Pump Disable Temperature 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.12.1 Verify a maximum of one SI pump is capable of injecting into the RCS.

SR 3.4.12.2 Verify each ECCS accumulator is isolated.

SR 3.4.12.3 Verify PORV block valve is open for each required PORV.

SR 3. 4.12. 4

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

N ot required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS cold leg temperature to ::. the OPPS enable temperature specified in the PTLR.

Perform a COT on OPPS.

FREQUENCY In accordance with the Surveillance Frequency Control Program Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.12-4 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

L TOP - RCSCL T > SI Pump Disable Temperature 3.4.12 SURVEILLANCE RE UIREMENTS continued SURVEILLANCE FREQUENCY SR 3.4.12.5 Perform CHANNEL CALIBRATION for each OPPS actuation channel.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.12-5 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

L TOP - RCSCL T::: SI Pump Disable Temperature 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.13.1 Verify no SI pumps are capable of injecting into the RCS.

SR 3.4.13.2 Verify each ECCS accumulator is isolated.

SR 3.4.13.3

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

Only required to be performed when complying with LCO 3.4.13.b.

FREQUENCY In accordance with the Surveillance Frequency Control Program Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and In accordance with the Surveillance Frequency Control Program Verify required RCS vent 2: 3 square inches open.

In accordance with the Surveillance Frequency Control Program SR 3.4.13.4 Verify PORV block valve is open for each required PORV.

Prairie Island Units 1 and 2 3.4.13-4 In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

LTOP-RCSCLT::: SI Pump Disable Temperature 3.4.13 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3. 4.13. 5

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

N ot required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS cold leg temperature to ::: the OPPS enable temperature specified in the PTLR.

Perform a COT on OPPS.

SR 3.4.13.6 Perform CHANNEL CALIBRATION for OPPS actuation channel.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.13-5 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

RCS Operational LEAKAGE 3.4.14 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3. 4.14.1

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

1. Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

2. Not applicable to primary to secondary LEAKAGE.

Verify RCS operational LEAKAGE within limits by performance of RCS water inventory balance.

SR 3. 4.14.2

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

N ot required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

Verify primary to secondary LEAKAGE is

150 gallons per day through any one SG.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.14-3 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

RCS Leakage Detection Instrumentation 3.4.16 ACTIONS (continued)

CONDITION D. All required monitors inoperable.

REQUIRED ACTION D.1 Enter LCO 3.0.3.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.16.1 Perform CHANNEL CHECK of the required containment radionuclide monitor.

SR 3.4.16.2 Perform COT of the required containment radionuclide monitor.

SR 3.4.16.3 Perform CHANNEL CALIBRATION of the required containment sump monitor.

SR 3.4.16.4 Perform CHANNEL CALIBRATION of the required containment radionuclide monitor.

COMPLETION TIME Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.16-3 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

ACTIONS ( continued)

CONDITION REQUIRED ACTION C.

Required Action and C.1 Be in MODE 3.

associated Completion Time of Condition A or AND B not met.

DOSE EQUIVALENT 1-131 > 30 µCi/gm.

C.2 Be in MODE 5.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.17.1 Verify reactor coolant DOSE EQUIVALENT XE-133 specific activity :S 580 µCi/gm.

RCS Specific Activity 3.4.17 COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.4.17-2 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE RE UIREMENTS continued SURVEILLANCE SR 3.4.17.2 Verify reactor coolant DOSE EQUIVALENT I-131 specific activity.::: 0.5 µCi/gm.

RCS Specific Activity 3.4.17 FREQUENCY In accordance with the Surveillance Frequency Control Program Between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a THERMAL

. POWER change of> 15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period Prairie Island Units 1 and 2 3.4.17-3 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.18 RCS Loops-Test Exceptions RCS Loops-Test Exceptions 3.4.18 LCO 3.4.18 The requirements ofLCO 3.4.4, "RCS Loops-MODES 1 and 2," may be suspended, with THERMAL POWER< P-7.

APPLICABILITY:

MODES 1 and 2 during startup and PHYSICS TESTS.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

THERMAL POWER

P-7.

A.1 Open reactor trip breakers.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.18.1 Verify THERMAL POWER is< P-7.

SR 3.4.18.2 Perform a COT for each power range neutron flux - low and intermediate range neutron flux channel and P-7.

FREQUENCY In accordance with the Surveillance Frequency Control Program Prior to initiation of startup and PHYSICS TESTS Prairie Island Units 1 and 2 3.4.18-1 Unit 1 -Amendment No. 226 Unit 2 -Amendment No..214

ACTIONS (continued)

CONDITION REQUIRED ACTION D. Two accumulators inoperable.

D.1 Enter LCO 3.0.3.

SURVEILLANCE REQUIREMENTS SR 3.5.1.1 SR 3.5.1.2 SR 3.5.1.3 SR 3.5.1.4 SURVEILLANCE Verify each accumulator isolation valve is fully open.

Verify borated water volume in each accumulator is~ 1250 cubic feet (25%) and::: 1290 cubic feet (91%).

Verify nitrogen cover pressure in each accumulator is~ 710 psig and::: 770 psig.

Verify boron concentration in each accumulator is

~2300 ppm.

Accumulators 3.5.1 COMPLETION TIME Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.5.1-2 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

Accumulators 3.5.1 SURVEILLANCE RE UIREMENTS continued SR 3.5.1.5 Prairie Island Units I and 2 SURVEILLANCE FREQUENCY Verify power is removed from each accumulator isolation valve operator when RCS pressure is In accordance with the Surveillance Frequency Control Program 2: 2000 psig.

3.5.1-3 Unit I - Amendment No. 226 Unit 2 - Amendment No. 214

SURVEILLANCE RE UIREMENTS SURVEILLANCE ECCS - Operating 3.5.2 FREQUENCY SR 3.5.2.1 Verify the following valves are in the listed position.

In accordance with the Surveillance Westing-Unit 1 house Valve Valve Number Number Position Function 32070 8801A OPEN SI Injection to RCS Cold Leg A 32068 8801B OPEN SI Injection to RCS Cold Leg B 32073 8806A OPEN SI Cold Leg Injection Line 32206 8816A CLOSED SI Pump Suction from RHR 32207 8816B CLOSED SI Pump Suction from RHR Westing-Unit2 house Valve Valve Number Number Position Function 32173 8801A OPEN SI Injection to RCS Cold Leg A 32171 8801B OPEN SI Injection to RCS Cold Leg B 32176 8806A OPEN SI Cold Leg Injection Line 32208 8816A CLOSED SI Pump Suction from RHR 32209 8816B CLOSED SI Pump Suction from RHR SR 3. 5.2.2

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

N ot required to be met for system vent flow paths opened under administrative control.

Verify each ECCS manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, is in the correct position.

Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.5.2-2 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.2.3 SURVEILLANCE Verify power to the valve operator has been removed for each valve listed in SR 3.5.2.1.

SR 3.5.2.4 Verify ECCS accessible locations susceptible to gas accumulation are sufficiently filled with water.

ECCS - Operating 3.5.2 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program SR 3.5.2.5 Verify ECCS inaccessible locations susceptible to gas Prior to entering accumulation are sufficiently filled with water.

MODE 3 after exiting shutdown cooling SR 3.5.2.6 Verify each ECCS pump's developed heat at the test flow point is greater than or equal to the required developed head.

SR 3.5.2.7 Verify each ECCS automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

In accordance with the Inservice Testing Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.5.2-3 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

ECCS - Operating 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.2.8 Verify each ECCS pump starts automatically on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.5.2.9 Verify each ECCS throttle valve listed below is in the In accordance with correct position.

the Surveillance Unit 1 Valve Number Unit 2 Valve Number Frequency Control Program SI-15-6 SI-15-7 SI-15-8 SI-15-9 2SI-15-6 2SI-15-7 2SI-15-8 2SI-15-9 SR 3.5.2.10 Verify, by visual inspection, each ECCS train In accordance with Prairie Island Units 1 and 2 containment sump suction inlet is not restricted by the Surveillance debris and the suction inlet strainers show no evidence Frequency Control of structural distress or abnormal corrosion.

Program 3.5.2-4 Unit 1 -Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.5.4.1 Verify RWST borated water volume is

~ 265,000 gallons (90%).

RWST 3.5.4 FREQUENCY In accordance with the Surveillance Frequency Control Program SR 3.5.4.2 Verify RWST boron concentration is~ 2600 ppm and In accordance with Prairie Island Units 1 and 2

3500 ppm.

the Surveillance Frequency Control Program 3.5.4-2 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

Containment Air Locks 3.6.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.6.2.1

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

1.

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

2.

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

Perform required air lock leakage rate testing in accordance with the Containment Leakage Rate Testing Program.

SR 3.6.2.2 Verify only one door in the air lock can be opened at a time.

FREQUENCY In accordance with the Containment Leakage Rate Testing Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.6.2-6 Unit 1 -Amendment No. 226 Unit 2 -Amendment No. 214

Containment Isolation Valves 3.6.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.6.3.1 Verify each 36-inch containment purge penetration blind flange is installed.

SR 3.6.3.2 Verify each 18-inch containment inservice purge penetration blind flange is installed.

SR 3. 6. 3.3

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

V alves and blind flanges in high radiation areas may be verified by use of administrative means.

Verify each containment isolation manual valve and blind flange that is located outside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls.

SR 3. 6. 3. 4

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

V alves and blind flanges in high radiation areas may be verified by use of administrative means.

Verify each containment isolation manual valve and blind flange that is located inside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls.

FREQUENCY Prior to entering M0DE4from M0DE5 Prior to entering M0DE4from M0DE5 In accordance with the Surveillance Frequency Control Program Prior to entering M0DE4from MODE 5 if not performed within the previous 92 days Prairie Island Units 1 and 2 3.6.3-6 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

Containment Isolation Valves 3.6.3 SURVEILLANCE REQUIREMENTS ( continued)

SURVEILLANCE SR 3.6.3.5 Verify the isolation time of each automatic power operated containment isolation valve is within limits.

SR 3.6.3.6 Not Used SR 3.6.3.7 Verify each automatic containment isolation valve that is not locked, sealed or otherwise secured in position, actuates to the isolation position on an actual or simulated actuation signal.

SR 3.6.3.8 Verify the combined leakage rate for all secondary containment bypass leakage paths is in accordance with the Containment Leakage Rate Testing Program.

FREQUENCY In accordance with the Inservice Testing Program In accordance with the Surveillance Frequency Control Program In accordance with the Containment Leakage Rate Testing Program Prairie Island Units 1 and 2 3.6.3-7 Unit 1 -Amendment No. 226 Unit 2 -Amendment No. 214

Containment Spray and Cooling Systems 3.6.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3. 6. 5.1

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

N ot required to be met for system vent flow paths opened under administrative control.

Verify each containment spray manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

FREQUENCY In accordance with the Surveillance Frequency Control Program SR 3.6.5.2 Operate each containment fan coil unit on low motor In accordance with speed for ~ 15 minutes.

the Surveillance Frequency Control Program SR 3.6.5.3 Verify containment spray locations susceptible to gas accumulation are sufficiently filled with water.

SR 3.6.5.4 Verify cooling water flow rate to each containment fan coil unit is ~ 900 gpm.

SR 3.6.5.5 Verify each containment spray pump's developed head at the flow test point is greater than or equal to the required developed head.

In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Inservice Testing Program Prairie Island Units 1 and 2 3.6.5-3 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

3.6 CONTAINMENT SYSTEMS 3.6.4 Containment Pressure LCO 3.6.4 Containment pressure shall be::: 2.0 psig.

APPLICABJLTIY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION A. Containment pressure not A.1 Restore containment within limits.

pressure to within limits.

B. Required Action and B.1 Bein MODE 3.

associated Completion Time not met.

AND B.2 Be in MODE 5.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.6.4.1 Verify containment pressure is within limits.

Containment Pressure 3.6.4 COMPLETION TIME 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months 6 hours 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.6.4-1 Unit 1 -Amendment No. 226 Unit 2 -Amendment No. 214

Containment Spray and Cooling Systems 3.6.5 SURVEILLANCE REQUIREMENTS ( continued)

SR 3.6.5.6 SR 3.6.5.7 SR 3.6.5.8 SURVEILLANCE Verify each automatic containment spray valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

Verify each containment spray pump starts automatically on an actual or simulated actuation signal.

Verify each containment cooling train starts automatically on an actual or simulated actuation signal.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program SR 3.6.5.9 Verify each spray nozzle is unobstructed.

Following maintenance which could result in nozzle blockage Prairie Island Units 1 and 2 3.6.5-4 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

Spray Additive System 3.6.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.6.6.1 Verify each spray additive manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

SR 3.6.6.2 Verify spray additive tank solution volume is ~ 2590 gal (89% ).

SR 3.6.6.3 Verify spray additive tank NaOH solution concentration is ~ 9% and ~ 11 % by weight.

SR 3.6.6.4 Verify each spray additive automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.6.6-2 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE Vacuum Breaker System 3.6.8 FREQUENCY SR 3.6.8.1 Verify each vacuum breaker train opens on an actual or simulated containment vacuum equal to or less than 0.5 psi and closes on an actual or simulated containment isolation signal.

In accordance with the Surveillance Frequency Control Program SR 3.6.8.2 Perform CHANNEL CALIBRATION.

Prairie Island Units 1 and 2 3.6.8-2 In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

3.6 CONTAINMENT SYSTEMS 3.6.9 Shield Building Ventilation System (SBVS)

LCO 3.6.9 Two SBVS trains shall be OPERABLE.

APPI1CAB1Ll1Y:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION A. One SBVS train A.l Restore SBVS train to inoperable.

OPERABLE status.

B. Required Action and B.1 Bein MODE 3.

associated Completion Time not met.

AND B.2 Bein MODE 5.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.6.9.1 Operate each SBVS train for::::. 15 minutes with heaters operating.

SBVS 3.6.9 COMPLETION TIME 7 days 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.6.9-1 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3.6.9.2 Perform required SBVS filter testing in accordance with the Ventilation Filter Testing Program (VFTP).

SR 3.6.9.3 Verify each SBVS train actuates on an actual or simulated actuation signal.

SR 3.6.9.4 Verify SBVS isolation dampers actuate on an actual or simulated signal.

SBVS 3.6.9 FREQUENCY In accordance with the VFTP In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.6.9-2 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.6.10.1 Verify one shield building access door in each access opening is closed.

SR 3.6.10.2 Verify each Shield Building Ventilation System (SBVS) train OPERABLE and produces a pressure equal to or more negative than -2.00 inches water gauge and maintains a pressure equal to or more negative than -1.82 inches water gauge in the annulus.

Shield Building 3.6.10 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.6.10-2 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

ACTIONS ( continued)

CONDITION D.

Required Action and associated Completion Time of Condition C not met.

REQUIRED ACTION D.1 Be in MODE 3.

D.2 Be in MODE 4.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3. 7.2.1

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

Only required to be performed in MODES 1 and 2.

Verify the isolation time of each MSIV is within limits.

SR 3. 7.2.2

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

Only required to be performed in MODES 1 and 2.

Verify each MSIV actuates to the isolation position on an actual or simulated actuation signal.

MSIVs 3.7.2 COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours FREQUENCY In accordance with the Inservice Testing Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.2-2 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

MFRVs and MFRV Bypass Valves 3.7.3 ACTIONS (continued)

CONDITION REQUIRED ACTION B. One or both MFRV B.1 Close and place in manual bypass valves inoperable.

or isolate flow through bypass valve(s).

AND B.2 Verify bypass valve( s) closed and in manual or flow through valve(s) isolated.

C. Required Action and C.1 Bein MODE 3.

associated Completion Time not met.

AND C.2 Bein MODE 4.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.3.1 Verify the isolation time of each MFRV and MFRV bypass valve is within limits.

SR 3.7.3.2 Verify each MFRV and MFRV bypass valve actuates to the isolation position on an actual or simulated actuation signal.

COMPLETION TIME 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Once per 7 days 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours FREQUENCY In accordance with the Inservice Testing Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.3-2 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.4.1 Verify one complete cycle of each SG PORV.

SR 3.7.4.2 Verify one complete manual cycle of each SG PORV block valve.

SGPORVs 3.7.4 FREQUENCY In accordance with the Inservice Testing Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.4-2 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3. 7.5.1

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

AFW train(s) may be considered OPERABLE during alignment and operation for steam generator level control if it is capable of being manually realigned to the AFW mode of operation.

Verify each AFW manual, power operated, and automatic valve in each water flow path, and in both steam supply flow paths to the steam turbine driven pump, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3. 7. 5.2

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

N ot required to be performed for the turbine driven AFW pump until prior to exceeding 10% R TP or within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after RCS temperature> 350°F.

Verify the developed head of each AFW pump at the flow test point is greater than or equal to the required developed head.

AFW System 3.7.5 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Inservice Testing Program Prairie Island Units 1 and 2 3.7.5-4 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3.7.5.3 ----------------------------N()TE----------------------------

AFW train(s) may be considered ()PERABLE during alignment and operation for steam generator level control, if it is capable of being manually realigned to the AFW mode of operation.

Verify each AFW automatic valve that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3. 7. 5. 4 ----------------------------N ()TES---------------------------

1. Not required to be performed for the turbine driven AFW pump until prior to exceeding 10% RTP or within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after RCS temperature> 350°F.

2. AFW train(s) may be considered ()PERABLE during alignment and operation for steam generator level control, if it is capable of being manually realigned to the AFW mode of operation.

Verify each AFW pump starts automatically on an actual or simulated actuation signal.

AFW System 3.7.5 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.5-5 Unit 1 -Amendment No. 226 Unit 2 - Amendment No. 214

ACTIONS ( continued)

CONDITION B. Required Action and associated Completion Time not met.

REQUIRED ACTION B.1 Be in MODE 3.

AND CSTs 3.7.6 COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months B.2 Be in MODE 4, without 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months reliance on steam generator for heat removal.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.7.6.1 Verify CSTs useable contents 2: 100,000 gal per operating unit.

FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.6-2 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3. 7. 7.1

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

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

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

SR 3.7.7.2 ----------------------------NOTE----------------------------

This SR only applies to those valves required to align CC System to support the safety injection or recirculation phase of emergency core cooling.

Verify each CC automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.7.7.3 Verify each CC pump starts automatically on an actual or simulated actuation signal.

CC System 3.7.7 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.7-2 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3. 7. 8.1

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

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

Verify each CL System manual, power operated, and automatic valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.8.2 Verify each required diesel driven CL pump starts and assumes load within one minute.

SR 3.7.8.3 Verify each stored diesel driven CL pump fuel oil supply contains ::::. 7 day supply.

SR 3.7.8.4 Verify OPERABILITY of required vertical motor driven CL pump.

SR 3.7.8.5 Verify each CL System automatic valve required to mitigate accidents that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

CL System 3.7.8 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.8-5 Unit 1 -Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE RE UIREMENTS continued SURVEILLANCE SR 3.7.8.6 Verify the required diesel driven and required vertical motor driven CL pumps start automatically on an actual or simulated actuation signal.

CL System 3.7.8 FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.8-6 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE RE UIREMENTS SURVEILLANCE Emergency CL Supply 3.7.9 FREQUENCY SR 3.7.9.1 Verify safeguards traveling screens OPERABLE.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.9-3 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.10.1 Operate each CRSVS train::::_ 15 minutes.

SR 3.7.10.2 Perform required CRSVS filter testing in accordance with the Ventilation Filter Testing Program (VFTP).

SR 3.7.10.3 Verify each CRSVS train actuates on an actual or simulated actuation signal.

SR 3.7.10.4 SR 3.7.10.5 Verify each CRSVS train in the Emergency Mode delivers 3600 to 4400 cfm through the associated CRSVS filters.

Perform required CRE unfiltered air inleakage testing in accordance with the Control Room Envelope Habitability Program.

CRSVS 3.7.10 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with VFTP In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Control Room Habitability Program Prairie Island Units 1 and 2 3.7.10-4 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3. 7.11.1 Verify each SCWS loop actuates on an actual or simulated actuation signal.

SR 3.7.11.2 Verify sews components OPERABLE in accordance with the Inservice Testing Program.

sews 3.7.11 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Inservice Testing Program Prairie Island Units 1 and 2 3.7.11-3 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

ACTIONS (continued)

CONDITION REQUIRED ACTION C. Required Action and C.1 Bein MODE 3.

associated Completion Time of Condition A or B AND not met in MODE 1, 2, 3, or 4.

C.2 Bein MODE 5.

D. Two ABSVS trains D.1 Suspend movement of inoperable due to irradiated fuel assemblies.

inoperable ABSVS boundary during movement of irradiated fuel assemblies.

OR Required Action and associated Completion Time of Condition A not met during movement of irradiated fuel assemblies.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.7.12.1 OperateeachABSVStrainfor.:::: 15minuteswith the heaters operating.

ABSVS 3.7.12 COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.12-2 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3.7.12.2 Perform required ABSVS filter testing in accordance with the Ventilation Filter Testing Program (VFTP).

SR 3.7.12.3 Verify each ABSVS train can produce a negative pressure within 20 minutes after initiation.

SR 3.7.12.4 Verify each ABSVS train actuates on an actual or simulated actuation signal.

ABSVS 3.7.12 FREQUENCY In accordance with the VFTP In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.12-3 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

3.7 PLANT SYSTEMS 3.7.14 Secondary Specific Activity Secondary Specific Activity 3.7.14 LCO 3.7.14 The specific activity of the secondary coolant shall be.::: 0.10 µCi/gm DOSE EQUIVALENT 1-131.

APPUCABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION A. Specific activity not within limit.

REQUIRED ACTION A.l Be in MODE 3.

A.2 Be in MODE 5.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.7.14.1 Verify the specific activity of the secondary coolant is.::: 0.10 µCi/gm DOSE EQUIVALENT 1-131.

COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.14-1 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

Spent Fuel Storage Pool Water Level 3.7.15 3.7 PLANT SYSTEMS 3.7.15 Spent Fuel Storage Pool Water Level LCO 3. 7.15 The spent fuel storage pool water level shall be:::: 23 ft over the top of irradiated fuel assemblies seated in the storage racks.

APPUCABIUIY:

During movement of irradiated fuel assemblies in the spent fuel storage pool.

ACTIONS CONDITION A. Spent fuel storage pool water level not within limit.

REQUIRED ACTION A.I -------------NOTE-------------

LCO 3.0.3 is not applicable.

COMPLETION TIME Suspend movement of Immediately irradiated fuel assemblies in the spent fuel storage pool.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.7.15.1 Verify the spent fuel storage pool water level is

23 ft above the top of the irradiated fuel assemblies seated in the storage racks.

FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.7.15-1 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

Spent Fuel Storage Pool Boron Concentration 3.7.16 SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.7.16.1 Verify the spent fuel storage pool boron concentration is within limit.

Prairie Island Units 1 and 2 3.7.16-2 FREQUENCY In accordance with the Surveillance Frequency Control Program Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.1 SURVEILLANCE Verify correct breaker alignment and indicated power availability for each required path.

FREQUENCY In accordance with the Surveillance Frequency Control Program SR 3.8.1.2

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

Prairie Island Units 1 and 2

1.

Performance of SR 3.8.1.6 satisfies this SR.

2.

All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.

3.

A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR in consideration of manufacturer's recommendations. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.6 must be met.

Verify each DG starts from standby conditions and achieves steady state voltage ~ 4084 V and

4400 V, and frequency~ 59.5 Hz and::: 60.5 Hz.

In accordance with the Surveillance Frequency Control Program 3.8.1-6 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3. 8.1.3

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

1.

DG loadings may include gradual loading in consideration of manufacturer's recommendations.

2.

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

3.

This Surveillance shall be conducted on only one DG at a time.

4.

This SR shall be preceded by and immediately follow without shutdown a successful performance of SR 3.8.1.2 or SR 3.8.1.6.

Verify each DG is synchronized and loaded and operates for~ 60 minutes at a load:

a.

Unit 1; ~ 2500 kW; and

b.

Unit 2; ~ 5100 kW and::: 5300 kW.

SR 3.8.1.4 Verify fuel oil level above lower limit switch in each day tank.

SR 3.8.1.5 Verify the fuel oil transfer system operates to transfer fuel oil from storage tank to the day tank.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.8.1-7 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE Sll 3.8.1.6 ----------------------------N()TE---------------------------

All DG starts may be preceded by an engine prelube period.

Verify each DG starts from standby condition and achieves:

a.

In:::_ 10 seconds, voltage:::: 3740 V and frequency:::: 58.8 Hz; and

b.

Steady state voltage:::: 4084 V and:::_ 4400 V, and frequency:::: 59.5 Hz and:::_ 60.5 Hz.

AC Sources-Operating 3.8.1 FREQUENCY In accordance with the Surveillance Frequency Control Program Sll 3. 8.1. 7 Verify each DG does not trip during and following a load rejection of:

In accordance with the Surveillance Frequency Control Program

1.

Unit 1:::: 650 kW; and

2.

Unit 2 :::: 860 kW.

Sll 3.8.1.8 Verify each DG's automatic trips are bypassed on an actual or simulated safety injection signal except:

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2

a.

Engine overspeed;

b.

Generator differential current; and

c.

Ground fault (Unit 1 only).

3.8.1-8 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

AC Sources-Operating 3.8.1 SURVEILLANCE RE UIREMENTS continued SURVEILLANCE FREQUENCY SR 3.8.1.9

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

Prairie Island Units 1 and 2

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

2. If performed with DG synchronized with offsite power, it shall be performed at a power factor

0.85. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable.

Verify each DG operates for~ 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s:

a.

For~ 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded:

Unit 1 ~ 2832 kW, and

.:::3000kW Unit 2 ~ 5400 kW, and

< 5940 kW; and

b.

For the remaining hours of the test loaded:

Unit 1 ~ 2500 kW, and Unit 2 ~ 4860 kW; and

c.

Achieves steady state voltage ~ 4084 V and.::: 4400 V; and frequency~ 59.5 Hz and::: 60.5 Hz.

In accordance with the Surveillance Frequency Control Program 3.8.1-9 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3.8.1.10 --------------------------- NOTES--------------------------

1.

All DG starts may be preceded by an engine prelube period.

2.

This Surveillance shall not be performed in MODE 1, 2, 3, or 4.

3.

12 Battery Charger not required to be energized in SR 3.8.1.lO(c) until completion of this SR during Unit 1 2011 refueling outage.*

Verify on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated safety injection actuation signal:

a.

De-energization of emergency buses;

b.

Load shedding from emergency buses; and

c.

DG auto-starts from standby condition and energizes emergency loads in ~ 60 seconds.

SR 3. 8.1.11 ----------------------------NOTE----------------------------

All DG starts may be preceded by an engine prelube period.

FREQUENCY In accordance with the Surveillance Frequency Control Program Verify on an actual or simulated loss of offsite power In accordance with signal that the DG auto-starts from standby condition.

the Surveillance Frequency Control Program

A modification will be installed during or prior to the Unit 1 2011 refueling outage to assure the 12 Battery Charger is automatically powered from its normal bus within 60 seconds. Compliance with this SR will be demonstrated after implementation of the modification.

Prairie Island Unit 1 -Amendment No. 226 Units 1 and 2 3.8.1-10 Unit 2-Amendment No. 214

ACTIONS ( continued)

CONDITION D. One or both stored DG fuel oil supply(s) < 6 days.

Required Action and associated Completion Time of Conditions A or C not met.

REQUIRED ACTION

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

Enter applicable Conditions and Required Actions ofLCO 3.7.8, "CL System" for CL train(s) made inoperable as a result of stored fuel oil properties not within limits.

D.1 Declare associated DG inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.3.1 Verify each stored DG fuel oil supply contains~ 7 day supply.

SR 3.8.3.2 Verify fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of, the Diesel Fuel Oil Testing Program.

Diesel Fuel Oil 3.8.3 COMPLETION TIME Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Diesel Fuel Oil Testing Program Prairie Island Units 1 and 2 3.8.3-2 Unit 1 -Amendment No. 226 Unit 2 -Amendment No. 214

DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.4.1 Verify battery terminal voltage is greater than or equal to the minimum established float voltage.

SR 3.8.4.2 Verify each battery charger supplies.:::: 250 amps at greater than or equal to the minimum established float voltage for.:::: 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Verify each battery charger can recharge the battery to the fully charged state within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months while supplying the demands of the var~ous continuous steady state loads, after a battery discharge to the bounding design basis event discharge state.

SR 3. 8.4.3

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

1.

The modified performance discharge test in SR 3.8.6.6 may be performed in lieu of SR 3.8.4.3.

2. This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.8.4-3 Unit 1 -Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE REQUIREMENTS SURVEILLANCE Sil 3.8.6.1

N()TE----------------------------

Not required to be met when battery terminal voltage is less than the minimum established float voltage of Sil 3.8.4.1.

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

Verify each battery float current is ::::. 2 amps.

Sil 3.8.6.2 Verify each battery pilot cell voltage is:::. 2.07 V.

Sil 3.8.6.3 Verify each battery connected cell electrolyte level is greater than or equal to minimum established design limits.

Sil 3.8.6.4 Verify each battery pilot cell temperature is greater than or equal to minimum established design limits.

Sil 3.8.6.5 Verify each battery connected cell voltage is> 2.07 V.

Battery Parameters 3.8.6 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.8.6-4 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE RE UIREMENTS continued SURVEILLANCE SR 3. 8. 6. 6

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

This Surveillance shall not be performed in MODE 1, 2, 3, or 4. However, credit may be taken for unplanned events that satisfy this SR.

Verify battery capacity is 2:. 80% of the manufacturer's rating when subjected to a performance discharge test or a modified performance discharge test.

Battery Parameters 3.8.6 FREQUENCY In accordance with the Surveillance Frequency Control Program 12 months when battery shows degradation, or has reached 85%

of the expected life with capacity

< 100% of manufacturer's rating 24 months when battery has reached 85% of the expected life with capacity 2:.

100% of manufacturer's rating Prairie Island Units 1 and 2 3.8.6-5 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

SURVEILLANCE RE UIREMENTS SURVEILLANCE Inverters-Operating 3.8.7 FREQUENCY SR 3.8.7.1 Verify correct inverter voltage and alignment to required Reactor Protection Instrument AC panels.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.8.7-2 Unit 1 -Amendment No. 226 Unit 2 - Amendment No. 214

ACTIONS ( continued)

CONDITION A. ( continued)

REQUIRED ACTION A.4 Initiate action to restore required inverter to

. OPERABLE status.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.8.8.1 Verify correct inverter voltage and alignment to required Reactor Protection Instrument AC panel.

Inverters-Shutdown 3.8.8 COMPLETION TIME Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.8.8-2 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

Distribution Systems-Operating 3.8.9 ACTIONS ( continued)

CONDITION REQUIRED ACTION E. Two trains with E. l Enter LCO 3.0.3.

inoperable distribution subsystems that result in a loss of safety function.

Two or more Reactor Protection Instrument AC panels inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.9.1 Verify correct breaker and switch alignments and voltage to safeguards AC, DC, and Reactor Protection Instrument AC electrical power distribution subsystems.

COMPLETION TIME Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.8.9-3 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE RE UIREMENTS SURVEILLANCE Distribution Systems-Shutdown 3.8.10 FREQUENCY SR 3.8.10.1 Verify correct breaker and switch alignments and voltage to required safeguards AC, DC, and Reactor Protection Instrument AC electrical power distribution subsystems.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.8.10-3 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

SURVEILLANCE RE UIREMENTS SURVEILLANCE Boron Concentration 3.9.1 FREQUENCY SR 3.9.1.1 Verify boron concentration is within the limits specified in COLR.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.9.1-2 Unit 1 - Amendment No. 226 Unit 2 - Amendment No. 214

Refueling Cavity Water Level 3.9.2 3.9 REFUELING OPERATIONS 3.9.2 Refueling Cavity Water Level LCO 3.9.2 Refueling cavity water level shall be maintained~ 23 ft above the top of reactor vessel flange.

APPLICABILTIY:

During movement of irradiated fuel assemblies within containment.

ACTIONS CONDITION A. Refueling cavity water level not within limit.

REQUIRED ACTION A.1 Suspend movement of irradiated fuel assemblies within containment.

SURVEILLANCE RE UIREMENTS SURVEILLANCE SR 3.9.2.1 Verify refueling cavity water level is~ 23 ft above the top of reactor vessel flange.

COMPLETION TIME Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.9.2-1 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

Nuclear Instrumentation 3.9.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.9.3.1 Perform CHANNEL CHECK of required channels.

SR 3. 9. 3.2

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

N eutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION of required channels.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.9.3-3 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

RHR and Coolant Circulation-High Water Level 3.9.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.9.5.1 Verify one RHR loop is in operation.

FREQUENCY In accordance with the Surveillance Frequency Control Program SR 3.9.5.2 Verify required RHR loop locations susceptible to gas accumulation are sufficiently filled with water.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.9.5-3 Unit 1 - Amendment No. 226 Unit 2-Amendment No. 214

RHR and Coolant Circulation-Low Water Level 3.9.6 ACTIONS CONDITION B. ( continued)

REQUIRED ACTION B.5.1 Close each penetration providing direct access from the containment atmosphere to the outside atmosphere with a manual or automatic isolation valve, or blind flange.

COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months B.5.2 Verify each penetration is 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months capable of being closed by an OPERABLE Containment Ventilation Isolation System.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.9.6.1 Verify one RHR loop is in operation.

SR 3.9.6.2 Verify correct breaker alignment and indicated power available to the required RHR pump that is not in operation.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.9.6-3 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

RHR and Coolant Circulation-Low Water Level 3.9.6 SURVEILLANCE RE UIREMENTS continued SURVEILLANCE FREQUENCY SR 3.9.6.3 Verify RHR loop locations susceptible to gas accumulation are sufficiently filled with water.

In accordance with the Surveillance Frequency Control Program Prairie Island Units 1 and 2 3.9.6-4 Unit 1 -Amendment No. 226 Unit 2 -Amendment No. 214

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.7 lnservice Testing Program (continued)

Prairie Island Units 1 and 2

a.

Testing frequencies applicable to the ASME Code for Operations and Maintenance of Nuclear Power Plants (ASME OM Code) and applicable Addenda as follows:

ASME OM Code and applicable Addenda terminology for inservice testing activities Weekly Monthly Semiquarterly Quarterly or every 3 months Semiannually or every 6 months Every 9 months Yearly or annually Biennially or every 2 years Required Frequencies for performing inservice testing activities At least once per 7 days At least once per 31 days At least once per 46 days At least once per 92 days At least once per 184 days At least once per 276 days At least once per 366 days At least once per 731 days

b.

The provisions of SR 3.0.2 are applicable to the above required Frequencies and to other normal and accelerated Frequencies specified 2 years or less in the Inservice Testing Program for performing inservice testing activities.

c.

The provisions of SR 3.0.3 are applicable to inservice testing activities; and

d.

Nothing in the ASME OM Code shall be construed to supersede the requirements of any TS.

5.0-12 Unit 1 - Amendment No. 226 Unit 2 -Amendment No. 214

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 Control Room Envelope Habitability Program (continued) 5.5.17 Prairie Island Units 1 and 2

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

The unfiltered air in-leakage limit for radiological challenges is the in-leakage flow rate assumed in the licensing basis analysis of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions of the licensing basis.

f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability and determining CRE unfiltered in-leakage as required by paragraph c.

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

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

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

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

5.0-31 Unit 1 -Amendment No. 226 Unit 2 -Amendment No. 214

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 226 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-42 AND AMENDMENT NO. 214 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-60 NORTHERN STATES POWER COMPANY-MINNESOTA PRAIRIE ISLAND NUCLEAR GENERATING PLANT. UNITS 1 AND 2 DOCKET NOS. 50-282 AND 50-306

1.0 INTRODUCTION

By application dated March 15, 2018 (Reference 1 ), as supplemented by letter dated September 17, 2018 (References 2), Northern States Power Company, doing business as Xcel Energy (Xcel Energy or the licensee), requested changes to the technical specifications (TSs) for Prairie Island Nuclear Generating Plant (PINGP).

The proposed changes would revise the PINGP TSs to adopt the U.S. Nuclear Regulatory Commission (NRC or Commission)-approved Technical Specifications Task Force (TSTF)

Standard Technical Specifications (STSs) Change Traveler TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control-RITSTF [Risk-Informed TSTF] Initiative 5b" (Reference 3) for PINGP.

The supplemental letter dated September 17, 2018, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register (FR) on May 22, 2018 (83 FR 23735).

2.0

2.1 REGULATORY EVALUATION

Description of the Proposed Changes The licensee proposed to modify the PINGP TSs by relocating specific surveillance frequencies to a licensee-controlled program (i.e., the surveillance frequency control program (SFCP) in accordance with Nuclear Energy Institute (NEI) 04-10, Revision 1 (Reference 4). The licensee stated that the proposed change is consistent with the adoption of NRC-approved TSTF-425, Revision 3. When implemented, TSTF-425, Revision 3, relocates most periodic frequencies of TS surveillances to the SFCP, and provides requirements for the new SFCP in the Administrative Controls section of the TSs. TSTF-425 states that all surveillance frequencies can be relocated except the following:

Frequencies that reference other approved programs for the specific interval, such as the lnservice Testing Program or the Primary Containment Leakage Rate Testing Program; Frequencies that are purely event-driven (e.g., "each time the control rod is withdrawn to the 'full out' position");

Frequencies that are event-driven, but have a time component for performing the surveillance on a one-time basis once the event occurs (e.g., "within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after thermal power reaching;?: [greater than or equal to] 95% RTP [rated thermal power]"); and Frequencies that are related to specific conditions (e.g., battery degradation, age and capacity) or conditions for the performance of a surveillance requirement (e.g., "drywall to suppression chamber differential pressure decrease").

The licensee proposed to relocate specific surveillance frequencies from the following TS Sections to the SFCP:

3.1 Reactivity Control System 3.2 Power Distribution Limits 3.3 Instrumentation 3.4 Reactor Coolant System (RCS) 3.5 Emergency Core Cooling Systems and Reactor Core Isolation Cooling (RCIC)

System 3.6 Containment Systems

3. 7 Plant Systems 3.8 Electrical Power Systems 3.9 Refueling Operations The licensee proposed to add the SFCP to PINGP TS, Section 5.0, "Administrative Controls."

Proposed TS 5.5.17 describes the requirements for the SFCP to control changes to the relocated surveillance frequencies to ensure that surveillances are performed at intervals to ensure limiting conditions for operation are met. The TS Bases for each affected surveillance would be revised to state that the surveillance frequency is controlled under the SFCP and were included in the application for information only. The proposed changes to the Administrative Controls section of the TSs include a specific reference to NEI 04-10, Revision 1, as the basis for making any changes to the surveillance frequencies when they are relocated out of the TSs.

The licensee proposed to remove the definition for "STAGGERED TEST BASIS" from TS Section 1.1 "Definitions," consistent with TSTF-425, which states that "Plants that adopt TSTF-425 will no longer use this defined term in the Technical Specifications and should remove it from Section 1.1. "

In a letter dated September 19, 2007 (Reference 5), the NRC staff approved Topical Report (TR) NEI 04-10, Revision 1, as an acceptable methodology for referencing in licensing actions to the extent specified in NEI 04-10, Revision 1, and under the limitations delineated in Section 4.0 of the NRC safety evaluation (SE) providing the basis for NRC acceptance of NEI 04-10, Revision 1.

2.2 Applicable Commission Policy Statements In the "Final Policy Statement: Technical Specifications Improvements for Nuclear Power Plants," dated July 22, 1993 (58 FR 39132), the NRC addressed the use of probabilistic safety analysis (PSA; currently referred to as probabilistic risk assessment or PRA) in STSs. In this policy statement, the NRC states (at 39135), in part:

The Commission believes that it would be inappropriate at this time to allow requirements which meet one or more of the first three criteria [of Title 1 O of the Code of Federal Regulations (10 CFR), Section 50.36(a)(2)(ii)(A) - (C)] to be deleted from Technical Specifications based solely on PSA (Criterion 4).

However, if the results of PSA indicate that Technical Specifications can be relaxed or removed, a deterministic review will be performed.

The Commission Policy in this regard is consistent with its Policy Statement on "Safety Goals for the Operation of Nuclear Power Plants," 51 FR 30028, published on August 21, 1986. The Policy Statement on Safety Goals states in

part,

... probabilistic results should also be reasonably balanced and supported through use of deterministic arguments. In this way, judgments can be made...

about the degree of confidence to be given these [probabilistic] estimates and assumptions. This is a key part of the process for determining the degree of regulatory conservatism that may be warranted for particular decisions. This defense-in-depth approach is expected to continue to ensure the protection of public health and safety....

The Commission will continue to use PSA, consistent with its policy on Safety Goals, as a tool in evaluating specific line-item improvements to Technical Specifications, new requirements, and industry proposals for risk-based Technical Specification changes.

Approximately 2 years later, the NRC provided additional detail concerning the use of PRA in the "Final Policy Statement: Use of Probabilistic Risk Assessment Methods in Nuclear Regulatory Activities," dated August 16, 1995 (60 FR 42622). In this publication, the NRC states, in part:

The Commission believes that an overall policy on the use of PRA methods in nuclear regulatory activities should be established so that the many potential applications of PRA can be implemented in a consistent and predictable manner that would promote regulatory stability and efficiency. In addition, the Commission believes that the use of PRA technology in NRC regulatory activities should be increased to the extent supported by the state-of-the-art in PRA methods and data and in a manner that complements the NRC's deterministic approach...

2.3 PRA addresses a broad spectrum of initiating events by assessing the event frequency. Mitigating system reliability is then assessed, including the potential for multiple and common cause failures. The treatment therefore goes beyond the single failure requirements in the deterministic approach. The probabilistic approach to regulation is, therefore, considered an extension and enhancement of traditional regulation by considering risk in a more coherent and complete manner....

Therefore, the Commission believes that an overall policy on the use of PRA in nuclear regulatory activities should be established so that the many potential applications of PRA can be implemented in a consistent and predictable manner that promotes regulatory stability and efficiency. This policy statement sets forth the Commission's intention to encourage the use of PRA and to expand the scope of PRA applications in all nuclear regulatory matters to the extent supported by the state-of-the-art in terms of methods and data....

Therefore, the Commission adopts the following policy statement regarding the expanded NRC use of PRA:

(1) The use of PRA technology should be increased in all regulatory matters to the extent supported by the state-of-the-art in PRA methods and data and in a manner that complements the NRC's deterministic approach and supports the NRC's traditional defense-in-depth philosophy.

(2) PRA and associated analyses (e.g., sensitivity studies, uncertainty analyses, and importance measures) should be used in regulatory matters, where practical within the bounds of the state-of-the-art, to reduce unnecessary conservatism associated with current regulatory requirements, regulatory guides, license commitments, and staff practices. Where appropriate, PRA should be used to support the proposal for additional regulatory requirements in accordance with 10 CFR 50.109 (Backfit Rule).

Appropriate procedures for including PRA in the process for changing regulatory requirements should be developed and followed. It is, of course, understood that the intent of this policy is that existing rules and regulations shall be complied with unless these rules and regulations are revised.

(3) PRA evaluations in support of regulatory decisions should be as realistic as practicable and appropriate supporting data should be publicly available for review.

(4) The Commission's safety goals for nuclear power plants and subsidiary numerical objectives are to be used with appropriate consideration of uncertainties in making regulatory judgments on the need for proposing and backfitting new generic requirements on nuclear power plant licensees.

Applicable Regulations In 10 CFR 50.36, "Technical Specifications," the NRC established its regulatory requirements related to the content of TSs. Pursuant to 10 CFR 50.36, TSs are required to include items in the following categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation; (3) surveillance requirements (SRs); (4) design features; and (5) administrative controls. These categories will remain in the PINGP TSs.

Section 50.36(c)(3) of 10 CFR states, "Surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." The FR notice published on July 6, 2009 (74 FR 31996), which announced the availability of TSTF-425, Revision 3, states that the addition of the SFCP to the TSs provides the necessary administrative controls to require that surveillance frequencies relocated to the SFCP are conducted at a frequency to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. The FR notice also states that changes to surveillance frequencies in the SFCP are made using the methodology contained in NEI 04-10.

Revision 1, including qualitative considerations, results of risk analyses, sensitivity studies and any bounding analyses, and recommended monitoring of structures, systems, and components (SSCs), and are required to be documented.

Existing regulatory requirements such as 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants" (i.e., the Maintenance Rule), and 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," require licensee monitoring of surveillance test failures and implementing corrective actions to address such failures. Such failures can result in the licensee increasing the frequency of a surveillance test. In addition, as required by proposed TS 5.5.17, changes to the frequencies listed in the SFCP shall be made in accordance with NEI 04-10, Revision 1; therefore, the licensee would be required to monitor the performance of SSCs for which surveillance frequencies are decreased to assure reduced testing does not adversely impact SSC reliability.

2.4 Applicable NRC Regulatory Guides and Review Plans Regulatory Guide (RG) 1.17 4, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 3 (Reference 6), describes an acceptable risk-informed approach for assessing the nature and impact of proposed permanent licensing basis changes by considering engineering issues and applying risk insights. This RG also provides risk acceptance guidelines for evaluating the results of such evaluations.

RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," Revision 1 (Reference 7), describes an acceptable risk-informed approach specifically for assessing proposed TS changes.

RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2 (Reference 8), describes an acceptable approach for determining whether the quality of the PRA, in total or the parts that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decisionmaking for light-water reactors (LWRs).

NUREG-0800, "Standard Review Plan [SRP] for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR Edition," Chapter 19, Section 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance" (Reference 9), provides general guidance for evaluating the technical basis for proposed risk-informed changes. Guidance on evaluating PRA technical adequacy is provided in SRP, Chapter 19, Section 19.1, Revision 3, "Determining the Technical Adequacy of Probabilistic Risk Assessment for Risk-Informed License Amendment Requests After Initial Fuel Load" (Reference 10). More specific guidance related to risk-informed TS changes is provided in SRP, Chapter 16, Section 16.1, Revision 1, "Risk-Informed Decisionmaking: Technical Specifications" (Reference 11 ), which includes changes to surveillance test intervals (STls) (i.e.,

surveillance frequencies) as part of risk-informed decisionmaking. Section 19.2 of the SRP references the same criteria as RG 1.17 4, Revision 3, and RG 1. 177, Revision 1, and states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following key principles:

The proposed change meets the current regulations unless it is explicitly related to a requested exemption or rule change; The proposed change is consistent with the defense-in-depth philosophy; The proposed change maintains sufficient safety margins; 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; The impact of the proposed change should be monitored using performance measurement strategies.

3.0 TECHNICAL EVALUATION

The licensee's adoption of TSTF-425, Revision 3, would provide for relocation of applicable surveillance frequencies to the SFCP and provide for the addition of the SFCP to the Administrative Controls section of TSs. Proposed changes to the Administrative Controls section of the TSs would also require the application of NEI 04-10, Revision 1, for any changes to surveillance frequencies within the SFCP. The licensee's application for the changes described in TSTF-425, Revision 3, included documentation regarding the technical adequacy of its PRA, which is recommended by RG 1.200, Revision 2. NEI 04-10, Revision 1, states that PRA methods are used with plant performance data and other considerations to identify and justify modifications to the surveillance frequencies of equipment at nuclear power plants. This is consistent with guidance provided in RG 1.17 4, Revision 3, and RG 1.177, Revision 1, in support of changes to STls.

3.1 Key Principles RG 1.177, Revision 1, identifies five key safety principles required for risk-informed changes to TSs. Each of these principles is addressed by NEI 04-10, Revision 1. Sections 3.1.1 through 3.1.5 of this section contain a discussion of the five principles, including the NRC staffs evaluation of how the licensee's license amendment request (LAR) satisfies each principle.

3.1.1 The Proposed Change Meets Current Regulations Section 50.36(c)(3) of 10 CFR requires that TSs include surveillances, which are "requirements relating to test, calibration, or inspection to assure that necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." The licensee is required by its TSs to perform surveillance tests, calibration, or inspection on specific safety-related equipment (e.g., reactivity control, power distribution, electrical, and instrumentation) to verify system operability. Surveillance frequencies are based primarily upon deterministic methods such as engineering judgment, operating experience, and manufacturer's recommendations. The licensee's use of NRG-approved methodologies identified in NEI 04-10, Revision 1, provides a way to establish risk-informed surveillance frequencies that complements the deterministic approach and supports the NRC's traditional defense-in-depth philosophy.

The SRs remain in the TSs, as required by 10 CFR 50.36(c)(3) but the frequency would be specified by reference to the SFCP, which per proposed TS 5.5.17, must ensure that LCOs are met. This change is analogous to other TS requirements in which the SRs are retained in TSs, but the related surveillance frequencies are located in licensee-controlled documents, such as surveillances performed in accordance with the lnservice Testing Program (as defined by PINGP TS 5.5.7) and the Containment Leakage Rate Testing Program (as defined by PINGP TS 5.5.14). Thus, this proposed change complies with 10 CFR 50.36(c)(3) by retaining the requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.

The regulatory requirements in 10 CFR 50.65 and 10 CFR Part 50, Appendix B, and the monitoring that would be required by NEI 04-10, Revision 1, via proposed TS 5.5.17, would ensure that surveillance frequencies are sufficient to assure that the requirements of 10 CFR 50.36 are satisfied and that any performance deficiencies will be identified and appropriate corrective actions taken. The licensee's SFCP required by proposed TS 5.5.17 ensures that SRs specified in the TSs are performed at intervals sufficient to assure that the above regulatory requirements are met. Based on the foregoing, the NRC staff concludes that the proposed change meets the first key safety principle of RG 1.177, Revision 1, by complying with current regulations.

3.1.2 The Proposed Change Is Consistent with the Defense-in-Depth Philosophy The defense-in-depth philosophy (i.e., the second key safety principle of RG 1.177, Revision 1) is maintained if:

A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation; Over-reliance on programmatic activities to compensate for weaknesses in plant design is avoided; System redundancy, independence, and diversity are preserved commensurate with the expected frequency, consequences of challenges to the system, and uncertainties (e.g., no risk outliers). (Because the scope of the proposed methodology is limited to revision of surveillance frequencies, the redundancy, independence, and diversity of plant systems are not impacted.);

Defenses against potential common cause failures (CCFs) are preserved, and the potential for the introduction of new CCF mechanisms is assessed; Independence of barriers is not degraded; Defenses against human errors are preserved; The intent of the General Design Criteria in 10 CFR Part 50, Appendix A, is maintained.

The changes to the Administrative Controls section of the TSs will require the application of NEI 04-10, Revision 1, for any changes to surveillance frequencies within the SFCP.

NEI 04-10, Revision 1, uses both the CDF and the large early release frequency (LERF) metrics to evaluate the impact of proposed changes to surveillance frequencies. In accordance with RG 1.174, Revision 3, and RG 1.177, Revision 1, changes to CDF and LERF are evaluated using a comprehensive risk analysis, which assesses the impact of proposed changes, including contributions from human errors and CCFs. Defense-in-depth is also included in the methodology explicitly as a qualitative consideration outside of the risk analysis, as is the potential impact on detection of component degradation that could lead to an increased likelihood of CCFs. The NRC staff concludes that both the quantitative risk analysis and the qualitative considerations provide reasonable assurance that defense-in-depth is maintained to ensure protection of public health and safety, satisfying the second key safety principle of RG 1.177, Revision 1.

3.1.3 The Proposed Change Maintains Sufficient Safety Margins The engineering evaluation that will be conducted by the licensee under the SFCP when frequencies are revised will assess the impact of the proposed frequency change to assure that sufficient safety margins are maintained. The guidelines used for making that assessment will include ensuring the proposed surveillance test frequency change is not in conflict with approved industry codes and standards or adversely affects any assumptions or inputs to the safety analysis; or, if such inputs are affected, justification is provided to ensure sufficient safety margin will continue to exist.

The design, operation, testing methods, and acceptance criteria for SSCs specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plants' licensing bases, including the Updated Safety Analysis Report and TS Bases, because these are not affected by changes to the surveillance frequencies.

Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis. On this basis, the NRC staff concludes that safety margins are maintained by the proposed methodology and, therefore, the third key safety principle of RG 1.177, Revision 1, is satisfied.

3.1.4 When Proposed Changes Using the SFCP Result in an Increase in CDF or Risk, the Increases Should Be Small and Consistent with the Intent of the Commission's Safety Goal Policy Statement RG 1.177, Revision 1, provides a framework for evaluating the risk impact of future proposed changes to surveillance frequencies using the SFCP, which requires identification of the risk contribution from impacted surveillances, determination of the risk impact from the change to the proposed surveillance frequency, and performance of sensitivity and uncertainty evaluations. Per proposed TS 5.5.17, changes to frequencies listed in the SFCP would require application of NEI 04-10, Revision 1. NEI 04-10, Revision 1, satisfies the intent of RG 1.177, Revision 1, guidance for evaluation of the change in risk, and for assuring that such changes are small by providing the technical methodology to support risk-informed TSs for control of surveillance frequencies.

3.1.4.1 PRA Technical Adequacy The technical adequacy of the licensee's PRA must be commensurate with the safety significance of the proposed TS change and the role the PRA plays in justifying the change.

That is, the greater the change in risk or the greater the uncertainty in that risk from the requested TS change, or both, the more rigor that must go into ensuring the technical adequacy of the PRA.

RG 1.200 provides regulatory guidance for assessing the technical adequacy of a PRA. The current revision (i.e., Revision 2) of this RG endorses, with clarifications and qualifications, the use of the following:

(1) American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) 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" (i.e., the PRA Standard) (Reference 12),

(2) NEI 00-02, "PRA Peer Review Process Guidance" (Reference 13), and (3) NEI 05-04, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," Revision 2 (Reference 14).

The PINGP PRA used to support the SFCP consists of internal events and fire PRA (FPRA) model. Capability Category (CC) II of the ASME/ANS PRA Standard is the target capability level for supporting requirements for the internal events PRA (IEPRA) for this application. Any identified deficiencies to those requirements are further assessed to determine any impacts to proposed decreases to surveillance frequencies, including the use of sensitivity studies where appropriate, in accordance with NEI 04-10, Revision 1.

In Attachment 2 of the LAR dated March 15, 2018, the licensee stated that a full scope peer review of the internal events model, excluding internal flooding, was performed in November 2010, applying the NEI 05-04, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," process and the ASME/ANS RA-Sa-2009 PRA Standard, as clarified by RG 1.200, Revision 2 (2009 ASME/ANS PRA Standard).

Subsequently, in September 2012, a focused scope peer review of the PINGP internal flooding events model was performed and applied the 2009 ASME/ANS PRA Standard. A second focused scope peer review of the PINGP internal events PRA was conducted in April 2012 to review the Flowserve N-9000 Abeyance Reactor Coolant Accident Modeling against 2009 ASME/ANS PRA Standard. A total of 31 facts and observations (F&Os) were established as result of the three peer reviews.

PINGP developed its FPRA using the guidance provided by NUREG/CR-6850 in support of transition to NFPA (National Fire Protection Association)-805. The PINGP model is based on the plant configuration assuming completion of all NFPA-805 design improvements which are not yet fully implemented. In June 2012, a full scope FPRA peer review that applied the NEI 07-12, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines," and

. the 2009 ASME/ANS PRA Standard was performed. A focused scope peer review was performed in March 2014 for model upgrade addressing hot gas layer temperature levels. A total of 41 F&Os were established as result of the two peer reviews.

Subsequent to both internal and fire peer reviews, PINGP implemented model and documentation changes to address 31 F&Os that resulted from the internal events peer reviews and 41 F&Os from the fire peer review. A findings closure review was conducted in October 2017, which applied NEI 05-04/07-12/12-06 Appendix X, "Close Out of Facts and Observations (F&Os)" (ADAMS Accession No. ML17086A451) (Appendix X), as well as requirements published in ASME/ANS PRA Standard and RG 1.200, Revision 2, to address the open F&Os. This review determined that 29 of the 31 internal events including internal flooding F&Os were closed and 35 of the 41 fire F&Os were closed.

The NRC staff allows licensees to use Appendix X guidance on an interim basis subject to conditions of acceptance outlined in NRC staff's letter to NEI dated May 3, 2017 (Reference 15).

The conditions of acceptance in the NRC staff's letter are:

A PRA method is new if it has not been reviewed by the NRC staff. There are two ways new methods are considered accepted by the NRC staff: (1) they have been explicitly accepted by the NRC (i.e., they have been reviewed, and the acceptance has been documented in a safety evaluation, frequently-asked-questions, or other publicly available organizational endorsement), or (2) they have been implicitly accepted by the NRC (i.e.,

there has been no documented denial) in multiple risk-informed licensing applications. The NRC's treatment of a new PRA method for closure of F&Os is described in the memorandum "U.S. Nuclear Regulatory Commission Staff Expectations for an Industry Facts and Observations Independent Assessment Process," dated May 1, 2017 (ADAMS Accession No. ML17121A271).

In order for the NRC to consider the F&Os closed so that they need not be provided in submissions of future risk-informed licensing applications, the licensee should adhere to the guidance in Appendix X in its entirety.

Following the Appendix X guidance will reinforce the NRC staff's confidence in the F&O closure process and potentially obviate the need for a more in-depth review.

In response to a NRC staff request for additional information (RAI) (Reference 2), the licensee provided responses that verified that the October 2017 closure review was performed consistent with the NRC staff accepted process discussed in the May 3, 2017, letter. Specifically, the licensee stated that:

The closure review included a written assessment and justification of whether each finding constituted a PRA upgrade or maintenance update as defined in the 2009 ASME/ANS PRA standard.

The selection of closure review members met the five criteria outlined in Appendix X,Section X.1.3.

The closure review team verified changes made to the PRA were adequately addressed such that CC-II requirements of the ASME/ANS PRA Standard, including clarifications imposed by the NRC Regulatory Guide 1.200 were met.

The findings closure assessment evaluated all finding-level F&Os, including those in which the underlying supporting requirements were assessed as "met".

For the internal events PRA finding closure review, two of the 31 F&Os were initially assessed at CC-I and now meet CC-II: LERF(LE)-C3 and Human Reliability (HR)-D2.

For LE-C3, an assessment and detailed discussion on the potential for equipment.repair for the top 95% of LERF sequences was added to the quantification notebook. For HR-D2, detailed assessments were added for all risk-significant pre-initiator Human Error Probabilities (HEP).

For the fire PRA finding closure review, three of the 41 F&Os were initially assessed at CC-1 and now meet CC-II: Cable Selection (CS)-81, Fire Scenario Selection (FSS)-D9, and FSS-F3. For CS-81, overcurrent coordination and breaker protection analysis is now complete. For FSS-D9, the PRA now evaluates smoke damage and includes failure due to such damage where applicable.- For FSS-F3, quantitative assessment of fire scenarios have been completed., Table 2-1, of the LAR addresses the open F&Os from the closure review process.

NRC staff requested additional information to clarify the impact of F&Os to the SFCP.

Finding CS-A10-01 stated that the cables routed through 16 fire compartments were not identified nor was the methodology specified. The LRA states in the "Resolution" column that

"[T]his SR [supporting requirement] is met at CC-I using a conservative approach." The NRC staff requested additional information related to the resolution of this F&O. The licensee stated in response to an NRC staff RAI that a new FPRA model was completed in April 2018. The licensee further stated that the cables in these 16 fire compartments are now mapped to the fire compartments. The NRC staff finds this approach acceptable to meet CC II for CS-A 10-01 since credited cables for FPRA functions for the 16 fire compartments are now identified and mapped.

Finding FSS-D7-01 highlighted that the unreliability of the fire detection system for the deluge system was not incorporated into the PRA. In response to request for additional information, the licensee stated that subsequent to the October 2017 F&O closure review, a new FPRA model incorporating the updated unreliability for the pre-action suppression systems and the non-suppression probability for the deluge systems was revised. In addition, the NRC staff requested an extent of condition analysis based on a letter dated May 24, 2016 (Reference 16) to the NRC, which stated that "the non-suppression probability has been calculated as sum of the unreliability and the unavailability values corresponding to each credited automatic detection and suppression system. This approach has been implemented in all the scenarios analyzed with detailed fire modeling crediting automatic suppression in the Fire PRA." In response to this question, the licensee updated unreliability values for the Carbon Dioxide (CARDOX) fire suppression system using generic values. The CARDOX system was modified in March 2017 to be actuated by the fire detection system instead of dedicated thermal detectors. The licensee states that after updating the CARDOX unavailability calculation, the new values are similar to and bounded by the previous values used in the Fire PRA quantification. The unreliability and unavailability of the CARDOX system is planned to be incorporated into the next Fire PRA model update. Based on the RAI response, the NRC staff finds that the licensee adequately addressed the finding since the updated Fire PRA incorporates the updated unreliability for the pre-action suppression systems, and the revision of the non-suppression probability for the deluge system, and also addressed extent of condition for other detection systems.

Finding SY-A17-01 indicates that the closure review team determined that this F&O should remain open until NRC approves the Flowserve N-9000 reactor coolant pump (RCP) seal model. The licensee performed a sensitivity study that removed credit for the abeyance seals in the current PRA model of record. This sensitivity study showed no more than a 5. 7 percent increase in the internal events CDF and no more than a 2. 7 percent increase in the Fire CDF.

The combined fire and internal events CDF increases no more than three percent. Based on the results of the sensitivity study, the NRC staff concludes that the Flowserve N-9000 RCP seal model does not have significant impact on the SFCP.

The NRC staff finds the remaining open closure review findings (Quantitative (QU)-C2, Equipment Selection (ES)-C1-01, FSS-F1-01, and Ignition Frequency (IGN)-A7-01) are either related to documentation or do not have a significant impact on the SFCP.

3.1.4.2 Scope of the PRA The proposed changes to the Administrative Controls section of the TSs would require the licensee to evaluate each proposed change to a relocated surveillance frequency using NEI 04-10, Revision 1, to determine its potential impact on CDF and LERF from internal events, fires, seismic, other external events, and shutdown conditions. In cases where a PRA of sufficient scope or quantitative risk models are unavailable, the licensee uses bounding analyses, or other conservative quantitative evaluations. A qualitative screening analysis may be used when the surveillance frequency impact on plant risk is shown to be insignificant.

The licensee has at-power internal events, internal flooding, and FPRA models. As required by proposed TS 5.5.17 and in accordance with NEI 04-10, Revision 1, the licensee will use these PRA models to perform quantitative evaluations to support the development of changes to surveillance frequencies in the SFCP. Section 2.3.3 of the LAR states, "PINGP fire PRA will be utilized in supplementary role since the fire PRA model is based on the PINGP plant configuration assuming completion of all NFPA-805 design improvements." In response to an NRC staff RAI, the licensee stated that the fire PRA does not [currently] represent the as-built, as-operated plant. Until the FPRA can be fully utilized, PINGP will use qualitative or bounding risk analysis per step 1 O of the NEI 04-10 guidance in conjunction with its FPRA model. The licensee intends to evaluate each surveillance test interval change that can be evaluated within the scope of the FPRA model to confirm the conservatism of the bounding fire evaluation. In response to the RAI, the licensee stated that once all NFPA-805 design modifications are installed and implemented, the risk evaluation of each implemented STI change remains valid with respect to the original STI evaluations performed using qualitative or bounding insights; and once the FPRA credited NFPA-805 plant modifications are installed, the FPRA model will be used to perform the quantitative risk assessment in accordance with NEI 04-10 process. The licensee also stated, in response to the RAI, that all plant modifications listed in Table S-2 of the NFPA-805 LAR are currently scheduled for completion within the timeframe specified. The NRC staff concludes that this approach outlined to evaluate fire risk is acceptable because the NRG-approved methodology in NEI 04-10, Revision 1, allows for several approaches to address fire risk impacts including qualitative or bounding risk analysis as well as a more refined analysis to be performed supporting changes to surveillance frequencies in the SFCP.

For other hazard groups for which a PRA model does not exist, a qualitative or bounding analysis, consistent with NEI 04-10, Revision 1, is performed to provide justification for the acceptability of the proposed test interval change. PINGP does not have a seismic PRA; however, a seismic margins assessment (SMA) was performed for PINGP with screening capacity at 0.3g. The licensee states that those SSCs impacted by SFCP frequency changes will be assessed against SMA and evaluated in accordance with NEI 04-10 bounding or qualitative analysis guidance. Similarly, PINGP does not maintain a shutdown PRA model; however, PINGP does operate under a shutdown risk management program outlined in NUMARC 91-06. The licensee states the shutdown risk management program procedures will be used to assess shutdown risk for proposed surveillance frequency changes. For other external hazards, i.e., high winds, tornado, external flooding, and other external hazards, the licensee states a qualitative or bounding approach will be utilized. Since the licensee's proposed analysis of external hazards is consistent with NEI 04-10 methodology for STI change evaluations in the absence of quantifiable PRA models, the NRC staff finds the licensee's treatment of external hazards acceptable.

Based on the application of NRG-approved NEI 04-10, Revision 1, which would be required by proposed TS 5.5.17, the NRC staff concludes that the licensee's evaluation methodology is sufficient to ensure the risk contribution of each surveillance frequency change is properly identified for evaluation and is consistent with Regulatory Position 2.3.2, "Scope of the Probabilistic Risk Assessment for Technical Specification Change Evaluations," of RG 1.177, Revision 1.

3.1.4.3 PRA Modeling The licensee's methodology includes the determination of whether the SSCs affected by a proposed change to a surveillance frequency are modeled in the PRA. Where the SSC is directly or implicitly modeled, a quantitative evaluation of the risk impact may be carried out.

The methodology adjusts the failure probability of the impacted SSCs, including any impacted CCF modes, based on the proposed change to the surveillance frequency. Where the SSC is not modeled in the PRA, bounding analyses are performed to characterize the impact of the proposed change to the surveillance frequency. Potential impacts on the risk analyses due to screening criteria and truncation levels are addressed by the requirements for PRA technical adequacy, consistent with guidance contained in RG 1.200, Revision 2, and by sensitivity studies identified in NEI 04-10, Revision 1.

By letter dated September 19, 2007 (Reference 5), the NRC staff approved NEl-04-10, Revision 1, which describes an acceptable methodology for licensees to evaluate changes in surveillance frequency. The NRC staff concludes that the PINGP PRA modeling is consistent with the guidance in NEl-04-10, Revision 1, and, therefore, the modeling is sufficient to ensure an acceptable evaluation of risk for the proposed changes in surveillance frequency, and is consistent with Regulatory Position 2.3.3, "Probabilistic Risk Assessment Modeling," of RG 1.177, Revision 1.

3.1.4.4 Assumptions for Time Related Failure Contributions The failure probabilities of SSCs modeled in PRAs may include a standby time-related contribution and a cyclic demand-related contribution. In Attachment 2, Section 2.5, "Identification of Key Assumptions," of the LAR dated March 15, 2018, the licensee states that the determination of standby failure rates are a key source of uncertainty and, therefore, sensitivity studies will be performed on standby failure rates for STI evaluations. The NEI 04-10, Revision 1, criteria adjust the time-related failure contribution of SSCs affected by the proposed change to a surveillance frequency. The licensee stated that this is consistent with RG 1.177, Revision 1, Section 2.3.3, which permits separation of the failure rate contributions into demand and standby for evaluation of SRs. If the available data does not support distinguishing between time-related failures and demand failures, then the change to surveillance frequency is conservatively assumed to impact the total failure probability of the SSC, including both standby and demand contributions. The SSC failure rate per unit time is assumed to be unaffected by the change in test frequency, such that the failure probability is assumed to increase linearly with time. This assumption will be confirmed by the monitoring and feedback described in NEI 04-10, Revision 1, as would be required by proposed TS 5.5.17.

The NEI 04-10, Revision 1, process imposed by proposed TS 5.5.17 requires consideration of qualitative sources of information with regard to potential impacts of test frequency on SSC performance, including industry and plant-specific operating experience, vendor recommendations, industry standards, and code-specified test intervals. Thus, the NRC staff concludes that the licensee's process would not be reliant upon risk analyses as the sole basis for the proposed changes because the licensee would apply the associated guidance in NRG-approved NEI 04-10, Revision 1.

The potential benefits of a reduced surveillance frequency, including reduced downtime and reduced potential for restoration errors, test-caused transients, and test-caused wear of equipment, are identified qualitatively, but are not quantitatively assessed. The NRC staff concludes that the licensee applied NRG-approved NEI 04-10, Revision 1, to employ reasonable assumptions with regard to extensions of STls, and the requested changes are consistent with Regulatory Position 2.3.4, "Assumptions in Completion Time and Surveillance Frequency Evaluations," of RG 1.177, Revision 1.

3.1.4.5 Sensitivity and Uncertainty Analyses The proposed amended TSs would require that changes to the frequencies listed in the SFCP be made in accordance with NEI 04-10, Revision 1. Therefore, the licensee would be required to have sensitivity studies that assess the impact of uncertainties from key assumptions of the PRA, uncertainty in the failure probabilities of the affected SSCs, impact on the frequency of initiating events; and any identified deviations from CC II of the PRA standard. Where the sensitivity analyses identify a potential impact on the proposed change, revised surveillance frequencies are considered, along with any qualitative considerations that may bear on the results of such sensitivity studies. In accordance with NEI 04-10, Revision 1, as required by proposed TS 5.5.17, the licensee would also perform monitoring and feedback of SSC performance, once the revised surveillance frequencies are implemented. Therefore, the NRC staff concludes that the licensee will appropriately consider the possible impact of PRA model uncertainty and sensitivity to key assumptions and model limitations, and the LAR is consistent with Regulatory Position 2.3.5, "Sensitivity and Uncertainty Analyses Relating to Assumptions in Technical Specification Change Evaluations," of RG 1.177, Revision 1, because the licensee will apply the associated guidance in NRG-approved NEI 04-10, Revision 1.

3. 1.4. 6 Acceptance Guidelines In accordance with NEI 04-10, Revision 1, as required by proposed TS 5.5.17, the licensee would quantitatively evaluate the change in total risk (including internal and external events contributions) in terms of CDF and LERF for both the individual risk impact of a proposed change in surveillance frequency and the cumulative impact from all individual changes to surveillance frequencies using NEI 04-10, Revision 1, in accordance with the TS SFCP. Each individual change to surveillance frequency must show a risk impact below 1 E-6 per year for change to CDF, and below 1 E-7 per year for change to LERF. These changes to CDF and LERF are consistent with the acceptance criteria of RG 1.174, Revision 3 (Reference 6), for very small changes in risk. Where the RG 1.17 4, Revision 3, acceptance criteria are not met, the process in NEI 04-10, Revision 1, either considers revised surveillance frequencies that are consistent with RG 1.17 4, Revision 3, or the process terminates without permitting the proposed changes. Where quantitative results are unavailable for comparison with the acceptance guidelines, appropriate qualitative analyses are required to demonstrate that the associated risk impact of a proposed change to surveillance frequency is negligible or insignificant. Otherwise, bounding quantitative analyses are required that demonstrate the risk impact is at least one order of magnitude lower than the RG 1.17 4, Revision 3, acceptance guidelines for very small changes in risk. In addition to assessing each individual SSC surveillance frequency change, the proposed SFCP would ensure that the cumulative impact of all changes result in a risk impact less than 1 E-5 per year for change to CDF, and less than 1 E-6 per year for change to LERF. Further, the proposed SFCP would ensure that the total CDF and total LERF be reasonably shown to be less than 1 E-4 per year and 1 E-5 per year, respectively. The NRC staff finds that these values are consistent with the acceptance criteria of RG 1.17 4, Revision 3, as referenced by RG 1.177, Revision 1 (Reference 7), for changes to surveillance frequencies.

Consistent with the NRC staff's SE dated September 19, 2007, for NEI 04-10, Revision 1 (Reference 5), the TS SFCP will require the licensee to calculate the total change in risk (i.e., the cumulative risk) by comparing a baseline model that uses failure probabilities based on surveillance frequencies prior to being changed per the SFCP, to a revised model that uses failure probabilities based on the changed surveillance frequencies.

The quantitative acceptance guidance of RG 1.17 4, Revision 3, is supplemented by qualitative information to evaluate the proposed changes to surveillance frequencies, including industry and plant-specific operating experience, vendor recommendations, industry standards, the results of sensitivity studies, and SSC performance data and test history. The final acceptability of the proposed change is based on all of these considerations and not solely on the PRA results. Post-implementation performance monitoring and feedback are also required to ensure continued reliability of the components. The licensee's application of NRG-approved NEI 04-10, Revision 1, provides acceptable methods for evaluating the risk increase associated with proposed changes to surveillance frequencies, consistent with Regulatory Position 2.4 of RG 1.177, Revision 1. Therefore, the NRC staff concludes that the proposed methodology satisfies the fourth key safety principle of RG 1.177, Revision 1, by assuring that any increase in risk is small, consistent with the intent of the Commission's Safety Goal Policy Statement.

3.1.5 The Impact of the Proposed Change Should Be Monitored Using Performance Measurement Strategies The licensee's proposed TS 5.5.17 requires application of NEI 04-10, Revision 1 (Reference 4),

in the SFCP. NEI 04-10, Revision 1, provides for performance monitoring of SSCs whose surveillance frequencies have been revised as part of a feedback process to ensure that the change in test frequency has not resulted in degradation of equipment performance and operational safety. The monitoring and feedback includes consideration of Maintenance Rule (i.e., 10 CFR 50.65) monitoring of equipment performance. In the event of SSC performance degradation, the surveillance frequency would be reassessed in accordance with the methodology, in addition to any corrective actions that may be required by the Maintenance Rule. The performance monitoring and feedback specified in NEI 04-10, Revision 1, which would be required by proposed TS 5.5.17, is sufficient to reasonably assure acceptable SSC performance and is consistent with Regulatory Position 3.2 of RG 1.177, Revision 1. Thus, the NRC staff concludes that the fifth key safety principle of RG 1.177, Revision 1, is satisfied.

3.1.6 Limitations and Conditions The NRC staff's SE in response to NEI 04-10, Section 4.0, states that:

The NRC staff finds that the methodology in NEI 04-10, Revision 1 is acceptable for referencing by licensees proposing to amend their TSs to establish a SFCP provided the following conditions are satisfied:

1. The licensee submits documentation with regards to PRA technical adequacy consistent with the requirements of RG 1.200, Section 4.2.

2. When a licensee proposes to use PRA models for which NRG-endorsed standards do not exist, the licensee submits documentation which identifies the quality characteristics of those models, consistent with RG 1.200 Sections 1.2 and 1.3. Otherwise, the licensee identifies and justifies the methods to be applied for assessing the risk contribution for those sources of risk not addressed by PRA models.

Section 3.1.4.1 of this SE discusses the technical adequacy of the licensee's PRA model and finds it to be consistent with NRC endorsed guidance. As discussed in Section 3.1.4.1 the NRC staff finds the information supplied in the LAR, as supplemented, supports the licensee's proposed PRA and therefore the limitations in the NRC staff's SE related to NEI 04-10 have been met.

3.2 Addition of Surveillance Frequency Control Program to Administrative Controls The licensee has included the SFCP and specific requirements for the SFCP as TS 5.5.17 in Section 5.0, Administrative Controls, as follows:

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

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

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

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

Based on its review in SE Section 3.1, above, the NRC staff finds that the proposed program is consistent with the model application of TSTF-425. In addition, the addition of TS 5.5.17 will ensure that surveillance frequencies are properly identified, are changed in accordance with an NRG-approved methodology, and are performed to ensure LCOs are met. Therefore, proposed TS 5.5.17 is acceptable.

3.3 TSTF-425 Optional Changes and Variations TSTF-425 applies the provisions of SR 3.0.2 to the frequencies established in the SFCP.

PINGP's TS SR 3.0.2 is different than the TS SR 3.0.2 provided in NUREG-1431 in that it contains a restriction regarding application of the 25 percent extension. PINGP TS SR 3.0.2 was developed in the Improved Technical Specification (ITS) transition to the STSs of NUREG-1431 Revision 1. During the conversion, not all evaluations were complete to move the frequencies to 24 months, along with the 24-month fuel cycle extension. NSPM justified the extension of these TS SR frequencies to a maximum of 24 months and proposed a restriction on the 1.25 frequency extension to all 24-month frequencies.

With the adoption of TSTF-425, NSPM proposes to update TS SR 3.0.2 such that it aligns with the NUREG-1431 TS SR 3.0.2. This proposed change would remove the restriction from TS SR 3.0.2 and relocate the restriction on specific 24-month frequencies to the SFCP when they are moved. Proposed TS SR 3.0.2 would only apply to these relocated 24-month frequencies once the licensee completes its evaluation in accordance with NEI 04-10.

The proposed TS changes to support alignment of TS SR 3.0.2 with STSs are:

Revise TS SR 3.0.2 to:

o Remove the restriction from the first paragraph of the TS o

Delete the second paragraph of SR 3.0.2 completely as it discussed the restriction on the 24-month frequencies o

Delete the "(1.25 times the interval specified)" in the third paragraph o

Change "interval" to "Frequency" and delete the "(1.25 times the interval specified)"

in the fourth paragraph Delete the NOTE in the "Frequency" column of TS SR 3.8.1.8 as it will not apply after adopting the standard TS SR 3.0.2 language Revise TS 5.5.7.b to:

o Delete the "(IST)" in the first sentence of TS 5.5.7.b as the acronym will no longer be used in this section o

Delete "as less than" before "2 years" and insert "or less" after "2 years" in TS 5.5.7.b in order to adopt the STS language o

Delete the last sentence of TS 5.5.7.b that discusses the 1ST Program testing frequency to be an exception to TS SR 3.0.2 The NRC staff reviewed the proposed changes to TS SR 3.0.2 and determined that changes to frequencies in the SFCP would be evaluated using the NRG-approved methodology and probabilistic risk guidelines contained in NEI 04-10, "Risk-Informed Technical Specification Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," Revision 1. The 24-month TS SRs that are modified to include the 25% extension, will be evaluated using the NEI 04-10 methodology, which includes qualitative considerations, risk analyses, sensitivity studies and bounding analyses, as necessary, and recommends monitoring of the performance of SSCs to assure that the increased frequency time does not adversely impact the SSCs. As a result, the NRC staff finds that the changes to TS SR 3.0.2 continue to meet 10 CFR 50.36(c)(3) requirement that SRs relating to test, calibration, or inspection assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met and, therefore, are acceptable.

PINGP TS contain plant-specific SRs that are not included in approved TSTF-425, Revision 3.

Approved TSTF-425, Revision 3, Section 2.0, states, "The proposed change relocates all periodic Surveillance Frequencies from the Technical Specifications and places the Frequencies under licensee control in accordance with a new program. All surveillances are relocated except" those that meet one of the criteria for surveillances that are listed in TSTF-425 not to be relocated to the SFCP. TSTF-425 does not add, delete, or modify the content of the surveillance requirements themselves. These statements denote that TSTF-425 applies to all surveillances, including the PINGP plant specific surveillances, that are periodic and do not meet one of the exclusion criteria. The NRC staff reviewed the marked-up SRs in the LAR to ensure that no surveillances were included that matched the exclusion criteria. The NRC staff determined that all marked-up surveillances included in the original LAR, as supplemented or corrected in the supplement, were included within the scope of approved TSTF-425, Revision 3.

Therefore, the SRs will continue to meet 10 CFR 50.36(c)(3), which requires that SRs relating to test, calibration, or inspection assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met and, therefore, are acceptable.

The licensee proposed three format or corrective changes to PINGP TSs. These changes are listed below:

TS SR 3.1.2.2 contains a hyphen one line below the "NOTES" box. This hyphen is not intended to be located there and is not related to any TS requirement. The hyphen would be deleted.

The TS SR 3.4.1.3 two-line Surveillance description is not correctly left justified. The justification is being corrected.

TS SR 3.8.4.3 contains a footnote (identified by an asterisk) that allowed a one-time frequency extension as part of License Amendment 218 (ADAMS Accession No. ML16256A514). The one-time extension of the surveillance test interval was for Unit 1, Cycle 29 only and has expired given that Unit 1 is now in Cycle 30. As part of the relocation of the frequency for TS SR 3.8.4.3, that asterisk and corresponding footnote would be removed as they no longer apply and would apply to the frequency when relocated to the SFCP.

The NRC staff notes that the TSs issued by the NRC does not contain a hyphen in TS SR 3.1.2.2, so removal is not necessary to be consistent with the PINGP license. The NRC staff evaluated the changes to TS SRs 3.4.1.3 and 3.8.4.3 and determined that they are corrective changes or updates that are consistent with the existing PINGP TSs and NUREG-1431 STSs.

Therefore, the proposed changes are acceptable.

3.4 Summary and Conclusions The NRC staff reviewed the licensee's proposed relocation of some surveillance frequencies to a licensee controlled document, and controlling changes to surveillance frequencies in accordance with a new program, the SFCP, identified in the Administrative Controls of TSs.

The SFCP and TS 5.5.17, references NEI 04-10, Revision 1, which provides a risk-informed methodology using plant-specific risk insights and performance data to revise surveillance frequencies within the SFCP. This NRG-approved methodology supports relocating surveillance frequencies from TSs to a licensee-controlled document.

The proposed licensee adoption of TS changes consistent with TSTF-425, Revision 3, and the use of risk-informed methodology of NEI 04-10, Revision 1, as required by proposed TS 5.5.17, satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.17 4, in that:

The proposed changes meet current regulations; The proposed changes are consistent with defense-in-depth philosophy; The proposed changes maintain sufficient safety margins; Increases in risk resulting from the proposed changes are small and consistent with the Commission's Safety Goal Policy Statement; and The impact of the proposed changes is monitored with performance measurement strategies.

The proposed licensee adoption of TS changes consistent with TSTF-425, Revision 3, and the use of NEI 04 10, Revision 1, as required by proposed TS 5.5.17, also meets the limitations and conditions included in the NRC staff's SE related to NEI 04-10.

The deletion of the definition "STAGGERED TEST BASIS" from TS Section 1.1 is consistent with TSTF-425. The NRC staff reviewed the PINGP TSs and confirmed that with the adoption of TSTF-425,as proposed in the LAR, the definition for "STAGGERED TEST BASIS" is no longer required as it no longer is used in the PINGP TSs.

The regulation in 10 CFR 50.36(c)(3) states: "Technical specifications will include items in the following categories: Surveillance Requirements. Surveillance Requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." The NRC staff finds that with the proposed relocation of surveillance frequencies to an owner-controlled document, the SFCP, which is controlled by the TS 5.5.17 requirement that the program ensure surveillance frequencies assure LCOs are met and any changes to those frequencies are appropriate under NEI 04-10, the licensee continues to meet the regulatory requirement of 10 CFR 50.36(c)(3).

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Minnesota State official was notified of the proposed issuance of the amendments on February 11, 2019. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes the requirements with respect to installation or use of a facility's components located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves 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 amendment involves no significant hazards consideration (83 FR 23735), and there has been no public comment on such finding. The amendment also changes a recordkeeping, reporting, or administrative procedures or requirements and makes editorial or other minor corrective changes.

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

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.

7.0 REFERENCES

1.

Sharp, S., Xcel Energy, letter to U.S. Nuclear Regulatory Commission,

Subject:

"Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program," dated March 15, 2018 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML18074A308).

2.

Sharp, S., Xcel Energy, letter to U.S. Nuclear Regulatory Commission,

Subject:

"Response to Request for Additional Information: Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program," dated September 17, 2018 (ADAMS Accession No. ML18261A231)

3.

Technical Specifications Task Force, letter to U.S. Nuclear Regulatory Commission,

Subject:

Transmittal of TSTF, Revision 3, "Relocate Surveillance Frequencies to Licensee Control-RITSTF Initiative 5b," dated March 18, 2009 (ADAMS Package Accession No. ML090850642).

4.

NEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," April 2007 (ADAMS Accession No. ML071360456}.

5.

Nieh, H. K., U.S. Nuclear Regulatory Commission, letter to Mr. Biff Bradley, Nuclear Energy Institute,

Subject:

"Final Safety Evaluation for Nuclear Energy Institute (NEI)

TR 04-10, Revision 1, 'Risk-Informed Technical Specifications Initiative 58, Risk-Informed Method for Control of Surveillance Frequencies (TAC No. MD6111 ),"' dated September 19, 2007 (ADAMS Accession No. ML072570267).

6.

U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Regulatory Guide 1.174, Revision 2, May 2011 (ADAMS Accession No. ML100910006).

7.

U.S. Nuclear Regulatory Commission, "An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications," Regulatory Guide 1.177, Revision 1, May 2011 (ADAMS Accession No. ML100910008).

8.

U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities,"

Regulatory Guide 1.200, Revision 2, March 2009 (ADAMS Accession No. ML090410014).

9.

U.S. Nuclear Regulatory Commission, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance,"

NUREG-0800, Section 19.2, June 2007 (ADAMS Accession No. ML071700658).

10.

U.S. Nuclear Regulatory Commission, "Determining the Technical Adequacy of Probabilistic Risk Assessment for Risk-Informed License Amendment Requests After Initial Fuel Load," NUREG-0800, Section 19.1, Revision 3, September 2012 (ADAMS Accession No. ML12193A107).

11.

U.S. Nuclear Regulatory Commission, "Risk-Informed Decision Making: Technical Specifications," NUREG-0800, Section 16.1, Revision 1, March 2007 (ADAMS Accession No. ML070380228).

12.

American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS)

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,"

February 2009, New York, NY

13.

NEI 00-02, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance,"

Revision 1, May 2006 and NEI 00-02 Appendix D, "Self Assessment Process for Addressing ASME PRA Standard RA-Sb-2005, as endorsed by NRC Regulatory Guide 1.200," October 2006 (ADAMS Accession Nos. ML061510619 and ML063390593, respectively).

14.

NEI 05-04 "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," NEI 05-04, Revision 2, November 2008 (ADAMS Accession No. ML083430462).

15.

Giitter, J., U.S. Nuclear Regulatory Commission, letter to Krueger, G., Nuclear Energy Institute,

Subject:

"U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance 05-04, 07-12, and 12-13, Close-Out of Facts and Observations" dated May 3, 2017 (ADAMS Accession No. ML17079A427)

16.

Northard, S., Prairie Island Nuclear Generating Plant, letter to U.S. Nuclear Regulatory Commission,

Subject:

"License Amendment Request to Adopt NFPA 805 Performance-Based Standard for Fire Protection for Light Water Reactors - Response to Request for Additional Information" dated May 24, 2016 (ADAMS Accession No. ML16152A046)

Principal Contributors: J. Patel J. Evans T. Sweat Date of issuance: April 16, 2019

v t e Letter Sequence Approval
EPID:L-2018-LLA-0065, TSTF-425 (Approved, Closed)
Initiation Request, Request Acceptance Administration Questions Answers 17 September 2018 Results Approval Other: ML23115A407
MONTHYEAR2018-09-17 [Table View]

ML19045A480

Text

SUBJECT:

Dear Mr. Sharp:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.1 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

7.0 REFERENCES

Subject:

Subject:

Subject:

Subject:

Subject:

Subject:

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