Text

Issuance of Amendments Request for Adoption of TSTF-425, Revision 3, Relocate Surveillance Frequencies to Licensee Control - Risk Informed Technical Specification Task Force Initiative 5b
	ML14322A461
Person / Time
Site:	Beaver Valley
Issue date:	03/06/2015
From:	Jeffrey Whited; Plant Licensing Branch 1
To:	Emily Larson; FirstEnergy Nuclear Operating Co
	Jeffery Whited, NRR/DORL 415-4090
References
	TAC MF2942, TAC MF2943
	Download: ML14322A461 (148)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 March 6, 2015 Mr. Eric A. Larson, Site Vice President FirstEnergy Nuclear Operating Company Beaver Valley Power Station Mail Stop A-BV-SEB1 P.O. Box 4, Route 168 Shippingport, PA 1 S077

SUBJECT:

BEAVER VALLEY POWER STATION, UNIT NOS. 1 AND 2 - ISSUANCE OF AMENDMENTS RE: REQUEST FOR ADOPTION OF TSTF-42S, REVISION 3, "RELOCATE SURVEILLANCE FREQUENCIES TO LICENSEE-CONTROL-RISK INFORMED TECHNICAL SPECIFICATION TASK FORCE INITIATIVE Sb" (TAC NOS. MF2942 AND MF2943)

Dear Mr. Larson:

The Commission has issued the enclosed Amendment No. 292 to Renewed Facility Operating License No. DPR-66 for the Beaver Valley Power Station, Unit No. 1 (BVPS-1 ), and Amendment No. 179 to Renewed Facility Operating License No. NPF-73 for the Beaver Valley Power Station, Unit No. 2 (BVPS-2). These amendments consist of changes to the Technical Specifications (TSs) in response to your application dated October 18, 2013, as supplemented by letters dated June 26, 2014, September 21, 2014, and February 4, 201S.

The amendments modify the BVPS-1 and BVPS-2 TSs by relocating specific surveillance frequencies to a licensee-controlled program with implementation of Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specification Initiative Sb, Risk-Informed Method for Control of Surveillance Frequencies." The changes are consistent with NRC-approved Technical Specifications Task Force (TSTF) Standard Technical Specifications (STS) change TSTF-42S, "Relocate Surveillance Frequencies to Licensee Control-[Risk Informed Technical Specifications Task Force] RITSTF Initiative Sb," Revision 3. The Federal Register notice published on July 6, 2009 (7 4 FR 31996), announced the availability of this TS improvement.

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

Docket Nos. 50-334 and 50-412

Enclosures:

1. Amendment No. 292 to DPR-66

2. Amendment No. 179 to NPF-73

3. Safety Evaluation cc w/encls: Distribution via ListServ Sincerely,

~A~.

Jeffrey A Whited, Project Manager Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 FIRSTENERGY NUCLEAR OPERATING COMPANY FIRSTENERGY NUCLEAR GENERATION, LLC DOCKET NO. 50-334 BEAVER VALLEY POWER STATION, UNIT NO. 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 292 Renewed License No. DPR-66

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by FirstEnergy Nuclear Operating Company, (FENOC)* acting on its own behalf and as agent for FirstEnergy Nuclear Generation, LLC (the licensees), dated October 18, 2013, as supplemented by letters dated June 26, 2014, September 21, 2014, and February 4, 2015, 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 regulations of the Commission; 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-66 is hereby amended to read as follows:

FENOC is authorized to act as agent for FirstEnergy Nuclear Generation, LLC, and has exclusive responsibility and control over the physical construction, operation, and maintenance of the facility.

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 292, are hereby incorporated in the license. The licensee 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.

FOR THE NUCLEAR REGULATORY COMMISSION 0~~

Attachment:

Changes to the Technical Specifications and Renewed Facility Operating License Date of Issuance: March 6, 2015 Douglas A. Broaddus, Chief Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

ATTACHMENT TO LICENSE AMENDMENT NO. 292 RENEWED FACILITY OPERATING LICENSE NO. DPR-66 DOCKET NO. 50-334 Replace the following page of the Renewed Facility Operating License with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

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

Remove 3.1.1-1 3.1.2-2 3.1.4-3 3.1.5-2 3.1.6-2 3.1.7.1-4 3.1.8-2 3.1.9-2 3.1.10-2 3.2.1-3 3.2.1-4 3.2.2-3 3.2.3-1 3.2.4-3 3.3.1-8 3.3.1-9 3.3.1-10 3.3.1-11 3.3.1-12 3.3.1-13 3.3.1-14 3.3.1-15 3.3.1-16 3.3.1-17 3.3.1-18 3.3.1-19 3.3.1-20 3.1.1-1 3.1.2-2 3.1.4-3 3.1.5-2 3.1.6-2 3.1.7.1-4 3.1.8-2 3.1.9-2 3.1.10-2 3.2.1-3 3.2.1-4 3.2.2-3 3.2.3-1 3.2.4-3 3.3.1-8 3.3.1-9 3.3.1-10 3.3.1-11 3.3.1-12 3.3.1-13 3.3.1-14 3.3.1-15 3.3.1-16 3.3.1-17 3.3.1-18 3.3.1-19 3.3.1-20 3.3.1-21

Remove Insert 3.3.2-5 3.3.2-5 3.3.2-6 3.3.2-6 3.3.2-7 3.3.2-7 3.3.2-8 3.3.2-8 3.3.2-9 3.3.2-9 3.3.2-10 3.3.2-10 3.3.2-11 3.3.2-11 3.3.2-12 3.3.2-12 3.3.2-13 3.3.2-13 3.3.2-14 3.3.3-2 3.3.3-2 3.3.4-1 3.3.4-1 3.3.4-2 3.3.5-2 3.3.5-2 3.3.6-2 3.3.6-2 3.3.7-2 3.3.7-2 3.3.8-2 3.3.8-2 3.4.1-2 3.4.1-2 3.4.2-1 3.4.2-1 3.4.3-2 3.4.3-2 3.4.4-1 3.4.4-1 3.4.5-2 3.4.5-2 3.4.5-3 3.4.5-3 3.4.6-2 3.4.6-2 3.4.7-3 3.4.7-3 3.4.8-2 3.4.8-2 3.4.9-2 3.4.9-2 3.4.11-4 3.4.11-4 3.4.12-3 3.4.12-3 3.4.12-4 3.4.12-4 3.4.13-2 3.4.13-2 3.4.15-3 3.4.15-3 3.4.16-2 3.4.16-2 3.4.17-1 3.4.17-1 3.4.19-1 3.4.19-1 3.5.1-1 3.5.1-1 3.5.1-2 3.5.1-2 3.5.2-2 3.5.2-2 3.5.2-3 3.5.2-3 3.5.4-2 3.5.4-2 3.5.5-1 3.5.5-1 3.6.2-4 3.6.2-4 3.6.3-4 3.6.3-4 3.6.3-5 3.6.3-5

Remove Insert 3.6.4-1 3.6.4-1 3.6.5-1 3.6.5-1 3.6.6-1 3.6.6-1 3.6.7-2 3.6.7-2 3.6.8-1 3.6.8-1 3.7.2-2 3.7.2-2 3.7.3-2 3.7.3-2 3.7.4-1 3.7.4-1 3.7.4-2 3.7.5-4 3.7.5-4 3.7.5-5 3.7.5-5 3.7.6-1 3.7.6-1 3.7.7-2 3.7.7-2 3.7.8-2 3.7.8-2 3.7.9-1 3.7.9-1 3.7.10-3 3.7.10-3 3.7.11-3 3.7.11-3 3.7.12-2 3.7.12-2 3.7.13-1 3.7.13-1 3.7.15-1 3.7.15-1 3.7.16-2 3.7.16-2 3.8.1-5 3.8.1-5 3.8.1-6 3.8.1-6 3.8.1-7 3.8.1-7 3.8.1-8 3.8.1-8 3.8.1-9 3.8.1-9 3.8.1-10 3.8.1-10 3.8.1-11 3.8.1-11 3.8.1-12 3.8.1-12 3.8.1-13 3.8.1-13 3.8.3-2 3.8.3-2 3.8.4-2 3.8.4-2 3.8.6-3 3.8.6-3 3.8.6-4 3.8.7-2 3.8.7-2 3.8.8-2 3.8.8-2 3.8.9-2 3.8.9-2 3.8.10-2 3.8.10-2 3.9.1-1 3.9.1-1 3.9.2-2 3.9.2-2 3.9.3-2 3.9.3-2 3.9.4-3 3.9.4-3 3.9.5-3 3.9.5-3 3.9.6-1 3.9.6-1 5.5-21 5.5-21 5.5-22 (3)

FENOC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, 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)

FENOC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source, or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; (5)

FENOC, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C.

This renewed operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter 1:

Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1)

Maximum Power Level FENOC is authorized to operate the facility at a steady state reactor core power level of 2900 megawatts thermal.

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 292, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.

(3)

Auxiliary River Water System (Deleted by Amendment No. 8)

Beaver Valley Unit 1 Amendment 292 Renewed Operating License DPR-66

3.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SOM)

SOM 3.1.1 LCO 3.1.1 SOM shall be within the limits specified in the COLR.

APPLICABILITY:

ACTIONS CONDITION MODE 2 with kett < 1.0, MODES 3, 4, and 5.

REQUIRED ACTION COMPLETION TIME A.

SOM not within limits.

A.1 Initiate boration to restore 15 minutes SOM to within limits.

SURVEILLANCE REQUIREMENTS SR 3.1.1.1 SURVEILLANCE Verify SOM to be within the limits specified in the COLR.

Beaver Valley Units 1 and 2 3.1.1 -1 FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 / 179

SURVEILLANCE REQUIREMENTS SR 3.1.2.1 SURVEILLANCE

- NOTE -

The predicted reactivity values may be adjusted (normalized) to correspond to the measured core reactivity prior to exceeding a fuel burnup of 60 effective full power days (EFPD) after each fuel loading.

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

Beaver Valley Units 1 and 2 3.1.2-2 Core Reactivity 3.1.2 FREQUENCY Once prior to entering MODE 1 after each refueling

- NOTE -

Only required after 60 EFPD In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 /179

Rod Group Alignment Limits 3.1.4 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.1.2 Initiate boration to restore required SOM to within limit.

AND D.2 Be in MODE 3.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 6 hours SURVEILLANCE REQUIREMENTS SR 3.1.4.1 SR 3.1.4.2 SR 3.1.4.3 SURVEILLANCE

- NOTE -

For Unit 1 only, this Surveillance is not required to be performed during rod motion and for the first hour following rod motion.

Verify individual rod positions within alignment limit.

Verify rod freedom of movement (trippability) by moving each rod not fully inserted in the core

~ 10 steps in either direction.

Verify rod drop time of each rod, from the fully withdrawn position, is::::; 2.7 seconds from the beginning of decay of stationary gripper coil voltage to dashpot entry, with:

a. Tav9 ~ 500°F and

b. All reactor coolant pumps operating.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Prior to criticality after each removal of the reactor head Beaver Valley Units 1 and 2 3.1.4-3 Amendments 2 9 2 / l 7 9

Shutdown Bank Insertion Limits 3.1.5 SURVEILLANCE REQUIREMENTS SR 3.1.5.1 SURVEILLANCE FREQUENCY Verify each shutdown bank is within the insertion limits In accordance specified in the COLR.

with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.1.5 - 2 Amendments 2 9 2 / 179

Control Bank Insertion Limits 3.1.6 ACTIONS (continued)

CONDITION REQUIRED ACTION B.2 Restore control bank sequence and overlap to within limits.

C.

Required Action and C.1 Be in MODE 2 with kett associated Completion

< 1.0.

Time not met.

SURVEILLANCE REQUIREMENTS SR 3.1.6.1 SURVEILLANCE Verify estimated critical control bank position is within the limits specified in the COLR.

COMPLETION TIME 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 6 hours FREQUENCY Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to achieving criticality SR 3.1.6.2 Verify each control bank insertion is within the insertion limits specified in the COLR.

In accordance with the Surveillance Frequency Control Program 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.

Beaver Valley Units 1 and 2 3.1.6 - 2 In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

Unit 1 Rod Position Indication 3.1.7.1 SURVEILLANCE REQUIREMENTS SR 3.1.7.1.1 SR 3.1.7.1.2 SURVEILLANCE Verify each control bank benchboard group step demand counter agrees within+/- 2 steps with the solid state indicators in the logic cabinet.

- NOTE -

Not required to be met during rod motion and for the first hour following rod motion.

Verify each RPI agrees within 12 steps of the group demand position for the full indicated range of rod travel.

FREQUENCY In accordance with the Surveillance Frequency Control Program Once prior to criticality after each removal of the reactor head Beaver Valley Units 1 and 2 3.1.7.1-4 Amendments 292 /179

SURVEILLANCE REQUIREMENTS SURVEILLANCE Unborated Water Source Isolation Valves 3.1.8 FREQUENCY SR 3.1.8.1 Verify each valve that isolates unborated water sources is secured in the closed position.

Within 15 minutes after a planned boron dilution or makeup activity Beaver Valley Units 1 and 2 3.1.8-2 In accordance with the Surveillance Frequency Control Program Amendments 292/179

PHYSICS TESTS Exceptions - MODE 2 3.1.9 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C.

RCS lowest loop average C.1 Restore RCS lowest loop 15 minutes temperature not within average temperature to limit.

within limit.

D.

Required Action and D.1 Be in MODE 3.

15 minutes associated Completion Time of Condition C not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.9.1 Perform a CHANNEL OPERATIONAL TEST on power range and intermediate range channels per Prior to initiation of PHYSICS TESTS SR 3.1.9.2 SR 3.1.9.3 SR 3.1.9.4 SR 3.3.1.6, SR 3.3.1.7, and Table 3.3.1-1.

Verify the RCS lowest loop average temperature is

~ 531°F.

Verify THERMAL POWER is::; 5% RTP.

Verify SDM is within the limits specified in the COLR.

Beaver Valley Units 1 and 2 3.1.9-2 In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS SURVEILLANCE RCS Boron Limitations < 500°F 3.1.10 FREQUENCY SR 3.1.10.1 Verify RCS boron concentration is > the ARO critical boron concentration.

In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.1.10-2 Amendments 2 9 2 / 179

SURVEILLANCE REQUIREMENTS

- NOTE -

Fa(Z) 3.2.1 During power escalation at the beginning of each cycle, THERMAL POWER may be increased until an equilibrium power level has been achieved, at which a power distribution map is obtained.

SURVEILLANCE SR 3.2.1.1 Verify F5(Z) is within limit.

Beaver Valley Units 1 and 2 3.2.1 - 3 FREQUENCY Once after each refueling prior to THERMAL POWER exceeding 75% RTP 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 F5(Z) was last verified In accordance with the Surveillance Frequency Control Program Amendments 292 /179

SURVEILLANCE REQUIREMENTS continued SR 3.2.1.2 SURVEILLANCE

- NOTE -

If measurements indicate that the maximum over z of [ F8(Z) I K(Z) ]

has increased since the previous evaluation of F8(Z):

a.

Increase F'el(Z) by the greater of a factor of 1.02 or by an appropriate factor specified in the COLR and reverify F'el(Z) is within limits or

b.

Repeat SR 3.2.1.2 once per 7 EFPD until either a.

above is met or two successive flux maps indicate that the maximum over z of [ F8(Z) I K(Z) ]

has not increased.

Verify F'el(Z) is within limit.

Fa(Z) 3.2.1 FREQUENCY Once after each refueling prior to THERMAL POWER exceed-ing 75% RTP 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'el(Z) was last verified In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.2.1 - 4 Amendments 2 9 2 / 179

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.2.2.1 Verify F~H is within limits specified in the COLR.

Beaver Valley Units 1 and 2 3.2.2 - 3 F~H 3.2.2 FREQUENCY Once after each refueling prior to THERMAL POWER exceeding 75% RTP In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

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.

APPLICABILITY:

MODE 1 with THERMAL POWER~ 50% RTP.

ACTIONS CONDITION A.

AFD not within limits.

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

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

Beaver Valley Units 1 and 2 3.2.3 - 1 COMPLETION TIME 30 minutes FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 292/ 179

SURVEILLANCE REQUIREMENTS SR 3.2.4.1 SR 3.2.4.2 SURVEILLANCE

- NOTES-

1.

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

~ 75% 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.

- NOTE -

Not 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> 75% RTP.

Verify QPTR is within limit using the movable incore detectors.

QPTR 3.2.4 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.2.4 - 3 Amendments 2 92 / l 7 9

SURVEILLANCE REQUIREMENTS

- NOTE -

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

SR 3.3.1.1 SR 3.3.1.2 SR 3.3.1.3 SR 3.3.1.4 SURVEILLANCE Perform CHANNEL CHECK.

- NOTE -

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is 2 15% RTP.

Compare results of calorimetric heat balance calculation to power range channel output. Adjust power range channel output if calorimetric heat balance calculations results exceed power range channel output by more than +2% RTP.

- NOTE -

Not required to be performed until 7 days after THERMAL POWER is 2 50% RTP.

Compare results of the incore detector measurements to Nuclear Instrumentation System (NIS) AFD. Adjust NIS channel if absolute difference is 2 3%.

- NOTE -

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

Perform T ADOT.

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 Beaver Valley Units 1 and 2 3.3.1 - 8 Amendments 292/ l 79

SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.5 SR 3.3.1.6 SURVEILLANCE Perform ACTUATION LOGIC TEST.

- NOTE-Not required to be performed for source range instrumentation until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after power has been reduced below P-6.

Perform COT.

Beaver Valley Units 1 and 2 3.3.1 - 9 RTS Instrumentation 3.3.1 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS continued SR 3.3.1.7 SURVEILLANCE

- NOTE -

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

Perform COT.

Beaver Valley Units 1 and 2 3.3.1 - 10 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 In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 / l 7 9

SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.8 SR 3.3.1.9 SR 3.3.1.10 SR 3.3.1.11 SURVEILLANCE

- NOTE -

Verification of setpoint is not required.

Perform T ADOT.

- NOTE -

Not required to be performed until 7 days after THERMAL POWER is:;:: 50% RTP.

Calibrate excore channels to agree with incore detector measurements.

- NOTES -

1.

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

2.

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

Perform COT.

RTS Instrumentation 3.3.1 FREQUENCY In accordance with the Surveillance Frequency Control Program Once per fuel cycle In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.3.1-11 Amendments 292/179

SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.12 SR 3.3.1.13 SR 3.3.1.14 SURVEILLANCE

- NOTE -

Verification of setpoint is not required.

Perform T ADOT.

- NOTE -

Verification of setpoint is not required.

Perform TADOT.

- NOTE -

Neutron detectors are excluded from response time testing.

Verify RTS RESPONSE TIME is within limits.

Beaver Valley Units 1 and 2 3.3.1 - 12 RTS Instrumentation 3.3.1 FREQUENCY In accordance with the Surveillance Frequency Control Program 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 Amendments 2 9 2 /179

FUNCTION

1.

Manual Reactor Trip

2.

Power Range Neutron Flux

a.

High

b.

Low

3.

Power Range Neutron Flux High Positive Rate

4.

Intermediate Range Neutron Flux S.

Source Range Neutron Flux Table 3.3.1-1 (page 1 of 9)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS 1,2 2

B SR 3.3.1.12 2

1,2 4

4 4

1,2 4

1(b), 2(1) 2 2

2 c

D E

R, S E

F,G H,I l,J SR 3.3.1.12 SR 3.3.1.1 SR 3.3.1.2 SR 3.3.1.3 SR 3.3.1.6 SR 3.3.1.9 SR 3.3.1.10 SR 3.3.1.14 SR 3.3.1.1 SR3.3.1.7 SR3.3.1.10 SR3.3.1.14 SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.14 SR 3.3.1.6 SR 3.3.1.10 SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.1 SR 3.3.1.6 SR 3.3.1.10 SR 3.3.1.1 SR 3.3.1.6 SR 3.3.1.10 (a)

With Rod Control System capable of rod withdrawal or one or more rods not fully inserted.

(b)

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

(c)

With keff ::2: 1.0.

RTS Instrumentation 3.3.1 UNIT 1 ALLOWABLE VALUE NA NA UNIT2 ALLOWABLE VALUE NA NA s 109.5% RTP s 109.5% RTP s 25.5% RTP s 25.5% RTP s 25.5% RTP s 25.5% RTP s 5.5% RTP with s 5.5% RTP time constant with time

e: 2 sec constant

e: 2 sec s 27.9% RTP s 27.9% RTP s 1.3 ES cps s 1.3 ES cps s1.3EScps s 1.3 ES cps (d)

With keff < 1.0, and all RCS cold leg temperatures 2 S00°F, and RCS boron concentrations the ARO critical boron concentration when the Rod Control System is capable of rod withdrawal, or one or more rods not fully inserted.

(e)

With all RCS cold leg temperatures 2 S00°F, and RCS boron concentrations the ARO critical boron concentration, when the Rod Control System is capable of rod withdrawal, or one or more rods not fully inserted.

(f)

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

(g)

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

Beaver Valley Units 1 and 2 3.3.1 - 13 Amendments 2 9 2 I 179

FUNCTION Table 3.3.1-1 (page 2 of 9)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS

6. Overtemperature 1,2 3

E SR 3.3.1.1 L'.T SR 3.3.1.3 SR 3.3.1.6 SR 3.3.1.9 SR 3.3.1.10 SR 3.3.1.14

7.

Overpower 1,2 3

E SR 3.3.1.1 liT SR 3.3.1.6 SR 3.3.1.10 SR 3.3.1.14

8.

Pressurizer Pressure

a.

Low 1 (h) 3 K

SR 3.3.1.1 SR3.3.1.6 SR 3.3.1.10 SR 3.3.1.14

b.

High 1,2 3

E SR 3.3.1.1 SR 3.3.1.6 SR 3.3.1.10 SR 3.3.1.14

9.

Pressurizer 1(h) 3 K

SR 3.3.1.1 Water Level -

SR 3.3.1.6 High SR 3.3.1.10

10. Reactor 1 (h) 3 per loop K

SR 3.3.1.1 Coolant SR 3.3.1.6 Flow-Low SR3.3.1.10 SR 3.3.1.14

11. Reactor 1 (h) 1 per RCP K

SR 3.3.1.12 Coolant Pump (RCP)

Breaker Position (h)

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

Beaver Valley Units 1 and 2 3.3.1 -14 RTS Instrumentation 3.3.1 UNIT 1 UNIT2 ALLOWABLE ALLOWABLE VALUE VALUE Refer to Note 1 Refer to Note 3 Refer to Note 2 Refer to Note4

? 1941 psig

? 1941 psig with time constants

? 2 sec for lead and

.,; 1 sec for lag

.,; 2389 psig

.,; 2379 psig

<; 92.5%

? 89.8%

? 89.6%

NA NA Amendments 2 92 /1 79

Table 3.3.1-1 (page 3 of 9)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS

12. Undervoltage 1(h) 1 per bus K

SR 3.3.1.8 RCPs SR 3.3.1.10 SR 3.3.1.14

13. Underfrequency 1 per bus RCPs

14. Steam 1,2 3 per SG Generator (SG) Water Level - Low Low

15. Turbine Trip

a.

Low Fluid 1 (i) 3 Oil Pressure Auto Stop (Unit 1)

Emergency Trip Header (Unit 2)

b.

Turbine 1 (i) 4 Stop Valve Closure

16. Safety 1,2 2 trains Injection (SI)

Input from Engineered Safety Feature Actuation System (ESFAS)

(h)

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

(i)

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

K E

L L

M SR 3.3.1.8 SR 3.3.1.10 SR 3.3.1.14 SR 3.3.1.1 SR 3.3.1.6(k)(I)

SR 3.3.1.10(k)(I)

SR 3.3.1.14 SR3.3.1.10 SR3.3.1.13 SR 3.3.1.10 SR 3.3.1.13 SR 3.3.1.12 RTS Instrumentation 3.3.1 UNIT 1 ALLOWABLE VALUE 2 2962 v 2 57.4 Hz 219.1%

2 42.9 psig 2 1% open NA UNIT2 ALLOWABLE VALUE 2 2962 v 2 57.45 Hz 220%

2 958 psig 2 1% open NA (k)

If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

(I)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance of the Nominal Trip Setpoint, or a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the predefined as-found acceptance criteria band, and the as-left setpoint tolerance band are specified in a document incorporated by reference into the Updated Final Safety Analysis Report.

Beaver Valley Units 1 and 2 3.3.1 - 15 Amendments 2 9 2 / 179

FUNCTION

17. Reactor Trip System Interlocks

a. Intermediate Range Neutron Flux, P-6

b. Low Power Reactor Trips Block, P-7

c. Power Range Neutron Flux, P-8

d. Power Range Neutron Flux, P-9

e. Power Range Neutron Flux, P-10

f. Turbine First Stage

Pressure, P-13

18. Reactor Trip BreakersG)

(RTBs)

19. Reactor Trip Breaker Undervoltage and Shunt Trip Mechanisms Table3.3.1-1 (page4of9)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS 2(g) 2 0

SR 3.3.1.10 SR 3.3.1.11 1 per train p

SR 3.3.1.5 4

p SR 3.3.1.10 SR 3.3.1.11 4

p SR3.3.1.10 SR 3.3.1.11 1,2 4

0 SR 3.3.1.10 SR 3.3.1.11 2

p SR 3.3.1.10 SR 3.3.1.11 1,2 2 trains N

SR 3.3.1.4 3(a), 4(a), 5(a) 2 trains c

SR 3.3.1.4 1,2 1 each per Q

SR 3.3.1.4 RTB 3(a>, 4(a), 5(a) 1 each per c

SR 3.3.1.4 RTB RTS Instrumentation 3.3.1 UNIT 1 UNIT2 ALLOWABLE ALLOWABLE VALUE VALUE 2'. 9E-11 amp 2'. 9E-11 amp NA NA s 30.5% RTP s 30.5% RTP s49.5% RTP s 49.5% RTP 2'. 9.5% RTP 2'.9.5% RTP ands 10.5%

ands 10.5%

RTP RTP s 10.5%

s 10.5%

turbine power turbine power NA NA NA NA NA NA NA NA

20. Automatic 1,2 2 trains M

SR3.3.1.5 NA NA Trip Logic 3(a), 4(a)' 5(a) 2 trains c

SR 3.3.1.5 NA NA (a)

With Rod Control System capable of rod withdrawal or one or more rods not fully inserted.

(g)

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

0)

Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB.

Beaver Valley Units 1 and 2 3.3.1-16 Amendments 2 9 2/ 1 7 9

Table 3.3.1-1 (page 5 of 9)

Reactor Trip System Instrumentation RTS Instrumentation 3.3.1 Note 1 (Unit 1 ): Overtemperature AT The Overtemperature AT Function Allowable Value shall not exceed the following nominal trip setpoint by more than 0.5% AT span for the AT channel, 0.5% AT span for the Tavg channel, 0.5%

AT span for the Pressurizer Pressure channel and 0.5% AT span for the f(AI) channel.

LlT 1

< LlT (K -K (l+r1S) [T l

T'] + K 3 (P - P') - f(AI)1 (l+r4S) -

0 1

2 l+r2S (l+r S)

'J where:

5 AT is measured RCS AT, °F.

AT o is loop specific indicated AT at RTP, °F.

Tis measured RCS average temperature, °F.

T' is Tavg at RTP specified in the COLR.

P is measured pressurizer pressure, psia.

P' is nominal pressurizer pressure specified in the COLR.

t1 & t2 1

t4 & t5 is the function generated by the lead-lag compensator for Tavg.

are the time constants utilized in the lead-lag compensator for T avg specified in the COLR.

is the function generated by the lag compensator for measured AT.

is the function generated by the lag compensator for measured Tavg.

are the time constants utilized in the lag compensators for AT and Tavg, respectively, specified in the COLR.

Sis the Laplace transform operator, sec-1.

K1 is specified in the COLR.

K2 is specified in the COLR.

~ is specified in the COLR.

f (AI) is a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers as specified in the COLR.

Beaver Valley Units 1 and 2 3.3.1 - 17 Amendments 2 9 2 /179

Table 3.3.1-1 (page 6 of 9)

Reactor Trip System Instrumentation RTS Instrumentation 3.3.1 Note 2 (Unit 1 ): Overpower L'l T The Overpower L'l T Function Allowable Value shall not exceed the following nominal trip setpoint by more than 0.5% L'l T span for the L'l T channel and 0.5% L'l T span for the Tavg channel.

L1 T 1

< L1 T [K -K ( r 3S ) T 1

- K [T I

- T"J]

(l+r4S) -

0 4

5 l+r3S (l+r5S) 6 (l+r S) where:

tlT is measured RCS tlT, °F.

L'lTo is loop specific indicated LlT at RTP, °F.

Tis measured RCS average temperature, °F.

T" is Tavg at RTP specified in the COLR.

K4 is specified in the COLR.

Ks is specified in the COLR.

K6 is specified in the COLR.

5 r3S is the function generated by the rate lag compensator for Tavg.

1+r3S

't3 1

't4 &'t5 is the time constant utilized in the rate lag compensator for T avg specified in the COLR.

is the function generated by the lag compensator for measured L'l T.

is the function generated by the lag compensator for measured T avg.

are the time constants utilized in the lag compensators for tlT and Tavg, respectively, specified in the COLR.

Sis the Laplace transform operator, sec-1.

Beaver Valley Units 1 and 2 3.3.1 -18 Amendments 2 9 2 I 179

Table 3.3.1-1 (page 7 of 9)

Reactor Trip System Instrumentation RTS Instrumentation 3.3.1 Note 3 (Unit 2): Overtemperature AT The Overtemperature AT Function Allowable Value shall not exceed the following nominal trip setpoint by more than 0.5% AT span for the AT channel, 0.5% AT span for the Tavg channel, 0.5% AT span for the Pressurizer Pressure channel and 0.5% AT span for the f(AI) channel.

where:

AT is measured RCS AT, °F.

1 1+r3S is the function generated by the lead-lag compensator on measured AT.

are the time constants utilized in the lead-lag compensator for AT specified in the COLR.

is the function generated by the lag compensator on measured AT.

r 3 is the time constant utilized in the lag compensator for AT specified in the COLR.

LlT0 is the loop specific indicated AT at RTP, °F.

K1 is specified in the COLR.

K2 is specified in the COLR.

is the function generated by the lead-lag compensator for Tavg.

are the time constants utilized in lead-lag compensator for Tavg specified in the COLR.

T is measured RCS average temperature, °F.

1 is the function generated by the lag compensator on measured T avg.

1+r6S r 6 is the time constant utilized in the lag compensator for Tavg specified in the COLR.

TI is T avg at RTP specified in the COLR.

Beaver Valley Units 1 and 2 3.3.1 - 19 Amendments 2 9 2 I 179

Table 3.3.1-1 (page 8 of 9)

Reactor Trip System Instrumentation RTS Instrumentation 3.3.1 Note 3 (Unit 2): Overtemperature AT (Continued)

K3 is specified in the COLR.

P is measured pressurizer pressure, psia.

P' is nominal pressurizer pressure specified in the COLR.

S is the Laplace transform operator, sec-1.

f 1(AI) is a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers as specified in the COLR.

Note 4 (Unit 2): Overpower AT The Overpower AT Function Allowable Value shall not exceed the following nominal trip setpoint by more than 0.5% AT span for the AT channel and 0.5% AT span for the Tavg channel.

~T (l+r1S) (

I

) < ~T {K -K < r7S ) (

1 ) T - K [ T ( 1

) -T"]}

(l+r2~) (1+r3S) -

o 4

5 (l+r7S) (1+r6S) 6 (l+r6S) where:

AT is measured RCS AT, °F.

1 1+r3S is the function generated by the lead-lag compensator on measured AT.

are time constants utilized in the lead-lag compensator for AT specified in the COLR.

is the function generated by the lag compensator on measured AT.

13 is the time constant utilized in the lag compensator for AT specified in the COLR.

ATo is the loop specific indicated AT at RTP, °F.

K4 is specified in the COLR.

Ks is specified in the COLR.

Beaver Valley Units 1 and 2 3.3.1 - 20 Amendments 2 9 2 I 179

Table 3.3.1-1(page9of9)

Reactor Trip System Instrumentation Note 4 (Unit 2): Overpower /1 T (Continued)

RTS Instrumentation 3.3.1 i-7S is the function generated by the rate-lag compensator for Tavg.

1+i-7S

't7 is the time constant utilized in the rate-lag compensator for T avg specified in the COLR.

1 is the function generated by the lag compensator on measured T avg.

1+i-6S

't6 is the time constant utilized in the lag compensator for T avg specified in the COLR.

K6 is specified in the COLR.

T is measured RCS average temperature, °F.

T" is Tavg at RTP specified in the COLR.

S is the Laplace transform operator, sec-1.

Beaver Valley Units 1 and 2 3.3.1 - 21 Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS

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

SR 3.3.2.1 SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.4 SR 3.3.2.5 SURVEILLANCE Perform CHANNEL CHECK.

Perform ACTUATION LOGIC TEST.

Perform MASTER RELAY TEST.

Perform COT.

- NOTE -

Verification of relay setpoints not required.

Perform TADOT.

Beaver Valley Units 1 and 2 3.3.2-5 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 Amendments 2 9 2 I 179

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.2.6 SR 3.3.2.7 SR 3.3.2.8 SR 3.3.2.9 SURVEILLANCE Perform SLAVE RELAY TEST.

- NOTE -

Verification of setpoint not required.

Perform T ADOT.

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

Perform CHANNEL CALIBRATION.

- NOTE-Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after SG pressure is ~ 600 psig.

Verify ESFAS RESPONSE TIMES are within limit.

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 Beaver Valley Units 1 and 2 3.3.2-6 Amendments 2 9 2 /179

FUNCTION Table 3.3.2-1 (page 1 of 7)

ESFAS Instrumentation 3.3.2 Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER UNIT 1 UNIT2 SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE ALLOWABLE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE VALUE

1. Safety Injection

a. Manual 1,2,3,4 2

B SR 3.3.2.7 NA NA Initiation

b. Automatic 1,2,3,4 2 trains c

SR 3.3.2.2 NA NA Actuation SR 3.3.2.3 Logic and SR 3.3.2.6 Actuation Relays

c. Containment 1,2,3 3

D SR 3.3.2.1 s 5.33 psig s 5.3 psig Pressure -

SR 3.3.2.4<el(fl High SR 3.3.2.8<el<fl SR 3.3.2.9

d. Pressurizer 1,2,3(a) 3 D

SR 3.3.2.1 2 1841 psig 2 1852 psig Pressure -

SR 3.3.2.4 Low SR 3.3.2.8 SR 3.3.2.9

e. Steam Line 1,2,3(a) 3 per steam D

SR 3.3.2.1 2 495.8 psig 2 494 psig Pressure -

line SR 3.3.2.4 with time with time Low SR 3.3.2.8 constant T1 constant T1 SR 3.3.2.9 2 50 secs and 2 50 secs T2 s 5 secs and T2 s 5 secs

2. Containment Spray Systems

a. Quench Spray (1) Manual 1,2,3,4 2 per train, B

SR 3.3.2.7 NA NA Initiation 2 trains (a)

Above the P-11 (Pressurizer Pressure) interlock.

(e)

If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

(f)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance of the Nominal Trip Setpoint, or a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the predefined as-found acceptance criteria band, and the as-left setpoint tolerance band are specified in a document incorporated by reference into the Updated Final Safety Analysis Report.

Beaver Valley Units 1 and 2 3.3.2-7 Amendments 2 9 2 / 179

FUNCTION Table 3.3.2-1 (page 2 of 7)

ESFAS Instrumentation 3.3.2 Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER UNIT 1 UNIT2 SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE ALLOWABLE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE VALUE

2. Containment Spray Systems (2) Automatic 1,2,3,4 2 trains c

SR 3.3.2.2 NA NA Actuation SR 3.3.2.3 Logic and SR 3.3.2.6 Actuation Relays (3) Contain-1,2,3 4

E SR 3.3.2.1 s 11.43 psig s 11.4 psig ment SR 3.3.2.4(e)(fl Pressure -

SR 3.3.2.s<e)(fl High High SR 3.3.2.9

b. Recirculation Spray (1) Automatic 1,2,3 2 trains F

SR 3.3.2.2 NA NA Actuation SR 3.3.2.3 Logic (2) Refueling 1,2,3 3

D SR 3.3.2.1

27' 4" and

32' 8" and Water SR 3.3.2.4(e)(t) s 27' 11" s 32' 10" Storage SR 3.3.2.S(e)(tJ Tank (RWST)

Level Low Coincident with Contain-1,2,3 4

E SR 3.3.2.1 s 11.43 psig s 11.4 psig ment SR 3.3.2.4(e)(tJ Pressure SR 3.3.2.s<e)(fl High High (e)

If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

(f)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance of the Nominal Trip Setpoint, or a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the predefined as-found acceptance criteria band, and the as-left setpoint tolerance band are specified in a document incorporated by reference into the Updated Final Safety Analysis Report.

Beaver Valley Units 1 and 2 3.3.2 - 8 Amendments 2 9 2 / 179

FUNCTION

3. Containment Isolation

a. Phase A Isolation (1) Manual Initiation (2) Automatic Actuation Logic and Actuation Relays (3) Safety Injection

b. Phase B Isolation (1) Manual Initiation (2) Automatic Actuation Logic and Actuation Relays (3) Contain-ment Pressure

- High High Table 3.3.2-1 (page 3 of 7)

ESFAS Instrumentation 3.3.2 Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER UNIT 1 UNIT 2 SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE ALLOWABLE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE VALUE 1,2,3,4 2

B SR 3.3.2.7 NA NA 1,2,3,4 2 trains c

SR 3.3.2.2 NA NA SR 3.3.2.3 SR 3.3.2.6 Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

1,2,3,4 2 per train, B

SR 3.3.2.7 NA NA 2 trains 1,2,3,4 2 trains c

SR 3.3.2.2 NA NA SR 3.3.2.3 SR 3.3.2.6 1,2,3 4

E SR 3.3.2.1 SR 3.3.2.4(e)(f) s; 11.43 psig s; 11.4 psig SR 3.3.2.a<e)(f)

SR 3.3.2.9 (e)

If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

(f)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance of the Nominal Trip Setpoint, or a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the predefined as-found acceptance criteria band, and the as-left setpoint tolerance band are specified in a document incorporated by reference into the Updated Final Safety Analysis Report.

Beaver Valley Units 1 and 2 3.3.2 - 9 Amendments 2 9 2 /179

Table 3.3.2-1 (page 4 of 7)

ESFAS Instrumentation 3.3.2 Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER UNIT 1 UNIT2 SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE VALUE

4. Steam Line Isolation

a. Manual 1,2<bl, 3(b) 2 per train, F

SR 3.3.2.7 NA NA Initiation 2 trains (Only applicable to Unit 2)

b. Automatic 1,2<bl, 3(b) 2 trains G

SR 3.3.2.2 NA NA Actuation SR 3.3.2.3 Logic and SR 3.3.2.6 Actuation Relays

c. Containment 1,2<bl, 3(b) 3 D

SR 3.3.2.1

<: 7.33 psig

<: 7.3 psig Pressure -

SR 3.3.2.4(e)(f)

Intermediate SR 3.3.2.8(e)(f)

High High SR 3.3.2.9

d. Steam Line Pressure (1) Low 1,2<bl, 3(a)(b) 3 per steam D

SR 3.3.2.1 2 495.8 psig 2 494 psig line SR 3.3.2.4 with time with time SR 3.3.2.8 constant 11 constant 11 SR 3.3.2.9 2 50 secs and 2 50 secs and 12 :<: 5 secs 12 :<: 5 secs (2) Negative 3(b)(c) 3 per steam D

SR 3.3.2.1

<: 104.2 psi

<: 103.6 psi Rate -

line SR 3.3.2.4 with a time with a time High SR 3.3.2.8 constant constant SR 3.3.2.9 2 50 secs 2 50 secs (a)

Above the P-11 (Pressurizer Pressure) interlock.

(b)

Except when all MSIVs are closed and de-activated.

(c)

Below the P-11 (Pressurizer Pressure) interlock when SI on steam line pressure low is blocked.

(e)

If the as-found channel setpoint is conservative with respect to the Allowable Value but qutside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

(f)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance of the Nominal Trip Setpoint, or a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable. The Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the predefined as-found acceptance criteria band, and the as-left setpoint tolerance band are specified in a document incorporated by reference into the Updated Final Safety Analysis Report.

Beaver Valley Units 1 and 2 3.3.2 - 10 Amendments 2 92 /1 79

FUNCTION

5. Turbine Trip and Feedwater Isolation

a. Automatic Actuation Logic and Actuation Relays

b. SG Water Level - High High (P-14)

c. Safety Injection

6. Auxiliary Feedwater

a. Automatic Actuation Logic and Actuation Relays

b. SG Water Level - Low Low

c. Safety Injection ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 5 of 7)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS 1,2<dl, 3(d) 2 trains G

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.6 1,2<d>, 3(d) 3 per SG D

SR 3.3.2.1 SR 3.3.2.4(e)(t)

SR 3.3.2.s<e)(IJ SR 3.3.2.9 UNIT 1 ALLOWABLE VALUE NA s 90.2%

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

1,2,3 1,2,3 2 trains G

3 per SG D

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.6 SR 3.3.2.1 SR 3.3.2.4(e)(t)

SR 3.3.2.s<e)(f)

SR 3.3.2.9 NA

>: 19.1%

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

UNIT2 ALLOWABLE VALUE NA s 92.7%

NA

>:20%

(d)

Except when all Main Feedwater Lines are isolated by either closed and deactivated MFIVs, or MFRVs and associated bypass valves, or closed manual valves.

(e)

If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

(f)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance of the Nominal Trip Setpoint, or a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the predefined as-found acceptance criteria band, and the as-left setpoint tolerance band are specified in a document incorporated by reference into the Updated Final Safety Analysis Report.

Beaver Valley Units 1 and 2 3.3.2 - 11 Amendments 2 9 2 / 179

FUNCTION

6. Auxiliary Feedwater

d. Undervoltage Reactor Coolant Pump

e. Trip of all Main Feedwater Pumps

7. Automatic Switchover to Containment Sump

a. Automatic Actuation Logic

b. Refueling Water Storage Tank (RWST) Level Extreme Low Coincident with Safety Injection Table 3.3.2-1 (page 6 of 7)

ESFAS Instrumentation 3.3.2 Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER UNIT 1 UNIT2 SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE ALLOWABLE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE VALUE 1,2 1 per bus H

SR 3.3.2.5

~ 2962 v

~ 2962 v SR 3.3.2.8 SR 3.3.2.9 1,2 1 per pump SR 3.3.2.7 NA NA SR 3.3.2.9 1,2,3,4 2 trains B

SR 3.3.2.2 NA NA SR 3.3.2.3 1,2,3,4 4

J SR 3.3.2.1

~ 13' 9" and

~ 31' 8" and SR 3.3.2.4(e)(f) s 14' 4" s 31' 10" SR 3.3.2.8(e)(f)

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

(e)

If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

(f)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance of the Nominal Trip Setpoint, or a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the predefined as-found acceptance criteria band, and the as-left setpoint tolerance band are specified in a document incorporated by reference into the Updated Final Safety Analysis Report.

Beaver Valley Units 1 and 2 3.3.2 -12 Amendments 2 9 2 / 179

Table 3.3.2-1 (page 7 of 7)

ESFAS Instrumentation 3.3.2 Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER UNIT 1 UNIT2 SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE VALUE

8. ESFAS Interlocks

a. Reactor Trip, 1,2,3 1 per train, F

SR 3.3.2.7 NA NA P-4 2 trains

b. Pressurizer 1,2,3 3

K SR 3.3.2.1

<;, 2004 psig

Pressure, SR 3.3.2.4 P-11 SR 3.3.2.8

c. Tavg - Low 1,2,3 1 per loop K

SR 3.3.2.1 2'. 540.5°F 2'. 540.5°F Low, P-12 SR 3.3.2.4 SR 3.3.2.8 Beaver Valley Units 1 and 2 3.3.2-13 Amendments 2 92 /179

SURVEILLANCE REQUIREMENTS

- NOTE-PAM Instrumentation 3.3.3 SR 3.3.3.1 and SR 3.3.3.2 apply to each PAM instrumentation Function in Table 3.3.3-1, except as noted in SR 3.3.3.2.

SR 3.3.3.1 SR 3.3.3.2 SR 3.3.3.3 SURVEILLANCE Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.

- NOTES -

1.

Neutron detectors are excluded from CHANNEL CALIBRATION.

2.

Not applicable to the Penetration Flow Path Containment Isolation Valve Position Function.

Perform CHANNEL CALIBRATION.

- NOTE -

Only applicable to the Penetration Flow Path Containment Isolation Valve Position Function.

Perform T ADOT.

Beaver Valley Units 1 and 2 3.3.3-2 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 Amendments 2 9 2 / 179

3.3 INSTRUMENTATION 3.3.4 Remote Shutdown System Remote Shutdown System 3.3.4 LCO 3.3.4 The Remote Shutdown System Functions shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS

- NOTE -

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION A.

One or more required A.1 Restore required Function Functions inoperable.

to OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

associated Completion Time not met.

AND B.2 Be in MODE4.

SURVEILLANCE REQUIREMENTS SURVEILLANCE COMPLETION TIME 30 days 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours FREQUENCY SR 3.3.4.1 Perform CHANNEL CHECK for each required indication instrumentation channel that is normally energized.

In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.3.4 - 1 Amendments 2 9 2 /179

Remote Shutdown System 3.3.4 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.4.2 SR 3.3.4.3 SURVEILLANCE

- NOTE -

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION for each required indication instrumentation channel.

FREQUENCY In accordance with the Surveillance Frequency Control Program Verify each required control circuit and transfer switch is In accordance capable of performing the intended function.

with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.3.4 - 2 Amendments 2 9 2 / 179

LOP DG Start and Bus Separation Instrumentation 3.3.5 ACTIONS (continued)

CONDITION REQUIRED ACTION D.

One or more Functions D.1 Restore inoperable with one channel per bus channel to OPERABLE inoperable.

status.

E.

Required Action and E.1 Enter applicable associated Completion Condition(s) and Required Time not met.

Action(s) for the associated DG made inoperable by LOP DG start or Bus Separation instrumentation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.3.5.1 SR 3.3.5.2 SR 3.3.5.3

- NOTE -

Verification of setpoint is not required.

Perform TADOT.

Perform CHANNEL CALIBRATION.

Verify ESF RESPONSE TIMES are within limit.

Beaver Valley Units 1 and 2 3.3.5 - 2 COMPLETION TIME 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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 Amendmen~ 292/179

Unit 2 Containment Purge and Exhaust Isolation Instrumentation 3.3.6 SURVEILLANCE REQUIREMENTS

- NOTE -

Refer to Table 3.3.6-1 to determine which SRs apply for each Containment Purge and Exhaust Isolation Function.

SR 3.3.6.1 SR 3.3.6.2 SR 3.3.6.3 SR 3.3.6.4 SURVEILLANCE Perform CHANNEL CHECK.

Perform COT.

- NOTE -

Verification of setpoint is not required.

Perform TADOT.

Perform CHANNEL CALIBRATION.

Beaver Valley Units 1 and 2 3.3.6 - 2 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 Amendments 2 9 2 / 179

ACTIONS (continued)

CONDITION D.

Required Action and D.1 associated Completion Time for Condition A or B not met during movement of recently irradiated fuel AND assemblies, or during movement of fuel D.2 assemblies over recently irradiated fuel assemblies.

SURVEILLANCE REQUIREMENTS CREVS Actuation Instrumentation 3.3.7 REQUIRED ACTION COMPLETION TIME Suspend movement of Immediately recently irradiated fuel assemblies.

Suspend movement of fuel Immediately assemblies over recently irradiated fuel assemblies.

- NOTE -

Refer to Table 3.3.7-1 to determine which SRs apply for each CREVS Actuation Function.

SR 3.3.7.1 SR 3.3.7.2 SR 3.3.7.3 SR 3.3.7.4 SURVEILLANCE Perform CHANNEL CHECK.

Perform COT.

- NOTE -

Verification of setpoint is not required.

Perform T ADOT.

Perform CHANNEL CALIBRATION.

Beaver Valley Units 1 and 2 3.3.7 - 2 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 Amendments 292 /179

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.3.8.1 Perform CHANNEL CHECK.

SR 3.3.8.2

- NOTE*

Boron Dilution Detection Instrumentation 3.3.8 FREQUENCY In accordance with the Surveillance Frequency Control Program Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

Beaver Valley Units 1 and 2 3.3.8-2 In accordance with the Surveillance Frequency Control Program Amendments 292 /l 79

RCS Pressure, Temperature, and Flow DNB Limits 3.4.1 SURVEILLANCE REQUIREMENTS SR 3.4.1.1 SR 3.4.1.2 SR 3.4.1.3 SR 3.4.1.4 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.

Verify RCS total flow rate is z 261,600 gpm and greater than or equal to the limit specified in the COLR.

- NOTE -

Not required to be performed until 7 days after z 95% RTP.

Verify by precision heat balance that RCS total flow rate is z 261,600 gpm and greater than or equal to the limit specified in the COLR.

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 Beaver Valley Units 1 and 2 3.4.1 - 2 Amendments 2 9 2 / 179

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 (T avg} shall be ?: 541°F.

APPLICABILITY:

MODE 1, MODE 2 with ke11?: 1.0.

ACTIONS CONDITION A.

T avg in one or more RCS loops not within limit.

A.1 REQUIRED ACTION Be in MODE 2 with Ke11

< 1.0.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.2.1 Verify RCS Tavg in each loop?: 541°F.

Beaver Valley Units 1 and 2 3.4.2 - 1 COMPLETION TIME 30 minutes FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS 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 P!T Limits 3.4.3 FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.4.3 - 2 Amendments 292 /l 79

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 Three RCS loops shall be OPERABLE and in operation.

APPLICABILITY:

ACTIONS CONDITION A.

Requirements of LCO not met.

MODES 1 and 2.

A.1 SURVEILLANCE REQUIREMENTS REQUIRED ACTION Be in MODE 3.

SURVEILLANCE SR 3.4.4.1 Verify each RCS loop is in operation.

Beaver Valley Units 1 and 2 3.4.4 - 1 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 Amendments 2 9 2 I 179

ACTIONS (continued)

CONDITION REQUIRED ACTION C.

One required RCS loop not C.1 Restore required RCS loop in operation with Rod to operation.

Control System capable of rod withdrawal.

OR C.2 Place the Rod Control System in a condition incapable of rod withdrawal.

D.

Two required RCS loops D.1 Place the Rod Control inoperable.

System in a condition incapable of rod OR withdrawal.

No RCS loops in operation.

AND D.2 Suspend operations that would cause introduction of coolant into the RCS with boron concentration less than required to meet SOM of LCO 3.1.1.

AND D.3 Initiate action to restore one RCS loop to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.5.1 Verify required RCS loops are in operation.

Beaver Valley Units 1 and 2 3.4.5-2 RCS Loops - MODE 3 3.4.5 COMPLETION TIME 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour Immediately Immediately Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 292I1 79

SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE RCS Loops - MODE 3 3.4.5 FREQUENCY SR 3.4.5.2 Verify steam generator secondary side water levels are

~ 28% (Unit 1 ), ~ 15.5% (Unit 2) for required RCS loops.

In accordance with the Surveillance Frequency Control Program SR 3.4.5.3

- NOTE -

Not 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 not in operation.

Beaver Valley Units 1 and 2 3.4.5 - 3 In accordance with the Surveillance Frequency Control Program Amend men ts 2 9 2 fl 7 9

ACTIONS (continued)

CONDITION REQUIRED ACTION B.

Two required loops B.1 Suspend operations that inoperable.

would cause introduction of coolant into the RCS with OR boron concentration less than required to meet SOM Required loop not in of LCO 3.1.1.

operation.

AND B.2 Initiate action to restore one loop to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS SR 3.4.6.1 SR 3.4.6.2 SR 3.4.6.3 SURVEILLANCE Verify required RHR or RCS loop is in operation.

Verify SG secondary side water levels are 2 28%

(Unit 1), 2 15.5% (Unit 2) for required RCS loops.

- NOTE -

Not 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 not in operation.

Beaver Valley Units 1 and 2 3.4.6 - 2 RCS Loops - MODE 4 3.4.6 COMPLETION TIME Immediately 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 Amendments 2 9 2 / l 7 9

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 SURVEILLANCE Verify required RHR loop is in operation.

Verify SG secondary side water level is 2 28% (Unit 1),

2 15.5% (Unit 2) in required SG.

- NOTE -

Not 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 not in operation.

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 Beaver Valley Units 1 and 2 3.4.7 - 3 Amendments 2 92 / l 7 9

RCS Loops - MODE 5, Loops Not Filled 3.4.8 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B.

No required RHR loop OPERABLE.

B.1 Suspend operations that Immediately would cause introduction of coolant into the RCS with boron concentration less than required to meet SOM Required RHR loop not in operation.

of LCO 3.1.1.

AND B.2 Initiate action to restore one RHR loop to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS SR 3.4.8.1 SR 3.4.8.2 SURVEILLANCE Verify required RHR loop is in operation.

- NOTE -

Not 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 not in operation.

Beaver Valley Units 1 and 2 3.4.8-2 Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

ACTIONS (continued)

CONDITION C.

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

C. 1 AND C.2 REQUIRED ACTION Be in MODE 3.

Be in MODE 4.

SURVEILLANCE REQUIREMENTS SR 3.4.9.1 SR 3.4.9.2 SURVEILLANCE Verify pressurizer water level is:::;; 92%.

Verify capacity of each required set of pressurizer heaters is ~ 150 kW.

Beaver Valley Units 1 and 2 3.4.9 - 2 Pressurizer 3.4.9 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 Amendments 2 9 2 / l 7 9

SURVEILLANCE REQUIREMENTS SR 3.4.11.1 SR 3.4.11.2.1 SR 3.4.11.2.2 SURVEILLANCE

- NOTE -

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

Perform a complete cycle of each block valve.

- NOTE -

Only required for Unit 1.

Perform a complete cycle of each PORV using:

a)

The normal air supply system, and b)

The backup nitrogen supply system.

- NOTE -

Only required for Unit 2.

Perform a complete cycle of each PORV.

Pressurizer PORVs 3.4.11 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 Beaver Valley Units 1 and 2 3.4.11 - 4 Amendments 2 9 2 I 179

ACTIONS (continued)

CONDITION G.

Two required PORVs inoperable.

Required Action and associated Completion Time of Condition D, E, or F not met.

OPPS inoperable for any reason other than Condition A, B, C, D, E, or F.

G. 1 SURVEILLANCE REQUIREMENTS REQUIRED ACTION Depressurize RCS and establish RCS vent of

2'. 2.07 square inches (Unit 1)

2'. 3.14 square inches (Unit 2).

SURVEILLANCE SR 3.4.12.1 SR 3.4.12.2 SR 3.4.12.3 Verify a maximum of one charging pump is capable of injecting into the RCS.

Verify each accumulator is isolated.

Verify required RCS vent

2'. 2.07 square inches (Unit 1)

2'. 3.14 square inches (Unit 2).

OPPS 3.4.12 COMPLETION TIME 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 Beaver Valley Units 1 and 2 3.4.12 - 3 Amendments 2 9 2 /179

SURVEILLANCE REQUIREMENTS (continued}

SR 3.4.12.4 SR 3.4.12.5 SURVEILLANCE Verify PORV block valve is open for each required PORV.

- NOTE -

Only applicable to Unit 1.

OPPS 3.4.12 FREQUENCY In accordance with the Surveillance Frequency Control Program Verify the ECCS automatic HHSI flow path is isolated.

In accordance with the Surveillance Frequency Control Program SR 3.4.12.6 SR 3.4.12.7

- NOTE -

Not 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 enable temperature specified in the PTLR.

Perform a COT on each required PORV, excluding actuation.

Perform CHANNEL CALIBRATION for each required PORV actuation channel.

Beaver Valley Units 1 and 2 3.4.12 - 4 In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SR 3.4.13.1 SR 3.4.13.2 SURVEILLANCE

- 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 is within limits by performance of RCS water inventory balance.

- NOTE -

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.

FREQUENCY In accordance with the Surveillance Frequency Control Program Verify primary to secondary LEAKAGE is ~ 150 gallons In accordance per day through any one SG.

with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.4.13 - 2 Amendments 2 9 2 / l 7 9

RCS Leakage Detection Instrumentation 3.4.15 SURVEILLANCE REQUIREMENTS SR 3.4.15.1 SR 3.4.15.2 SR 3.4.15.3 SR 3.4.15.4 SURVEILLANCE FREQUENCY Perform CHANNEL CHECK of the required containment In accordance atmosphere radioactivity monitor.

with the Surveillance Frequency Control Program Perform COT of the required containment atmosphere radioactivity monitor.

Perform CHANNEL CALIBRATION of the required containment sump monitor.

Perform CHANNEL CALIBRATION of the required containment atmosphere radioactivity monitor.

In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.4.15-3 Amendments 2 9 2 I 1 7 9

SURVEILLANCE REQUIREMENTS SR 3.4.16.1 SR 3.4.16.2 SR 3.4.16.3 SURVEILLANCE Verify reactor coolant gross specific activity

~ 100/E µCi/gm.

- NOTE-Only required to be performed in MODE 1.

Verify reactor coolant DOSE EQUIVALENT 1-131 specific activity~ 0.35 µCi/gm.

- NOTE-Not required to be performed until 31 days after a minimum of 2 effective full power days and 20 days of MODE 1 operation have elapsed since the reactor was last subcritical for :e: 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

Determine E from a sample taken in MODE 1 after a minimum of 2 effective full power days and 20 days of MODE 1 operation have elapsed since the reactor was last subcritical for :e: 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

RCS Specific Activity 3.4.16 FREQUENCY In accordance with the Surveillance Frequency Control Program 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 In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.4.16-2 Amendments 2 9 2 / 179

3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 RCS Loop Isolation Valves RCS Loop Isolation Valves 3.4.17 LCO 3.4.17 Each RCS hot and cold leg loop isolation valve shall be open with power removed from each isolation valve operator.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS

-NOTE-Separate Condition entry is allowed for each RCS loop isolation valve.

CONDITION REQUIRED ACTION COMPLETION TIME A.

Power available to one or A.1 Remove power from loop 30 minutes more loop isolation valve isolation valve operators.

operators.

B.

B.1 Maintain valve(s) closed.

Immediately

- NOTE -

All Required Actions shall AND be completed whenever this Condition is entered.

B.2 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AND One or more RCS loop isolation valves closed.

B.3 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify each RCS loop isolation valve is open and power is removed from each loop isolation valve operator.

In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.4.17 - 1 Amendments 2 9 2 /179

3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.19 RCS Loops - Test Exceptions RCS Loops - Test Exceptions 3.4.19 LCO 3.4.19 The requirements of LCO 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 SR 3.4.19.1 SR 3.4.19.2 SR 3.4.19.3 SURVEILLANCE Verify THERMAL POWER is< P-7.

Perform a COT for each power range neutron flux - low channel, intermediate range neutron flux channel, P-10 and P-13.

Perform an ACTUATION LOGIC TEST on P-7.

FREQUENCY In accordance with the Surveillance Frequency Control Program Prior to initiation of startup and PHYSICS TESTS Prior to initiation of startup and PHYSICS TESTS Beaver Valley Units 1 and 2 3.4.19-1 Amendments 2 9 2 /179

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1 Accumulators Accumulators 3.5.1 LCO 3.5.1 Three ECCS accumulators shall be OPERABLE.

APPLICABILITY:

MODES 1 and 2, MODE 3 with RCS pressure> 1000 psig.

ACTIONS CONDITION REQUIRED ACTION A.

One accumulator A.1 Restore boron inoperable due to boron concentration to within concentration not within limits.

limits.

B.

One accumulator B.1 Restore accumulator to inoperable for reasons OPERABLE status.

other than Condition A.

C.

Required Action and C.1 Be in MODE 3.

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

C.2 Reduce RCS pressure to

=;; 1000 psig.

D.

Two or more accumulators D.1 Enter LCO 3.0.3.

inoperable.

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

Beaver Valley Units 1 and 2 3.5.1 - 1 COMPLETION TIME 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 24 hours 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.1.2 SR 3.5.1.3 SR 3.5.1.4 SR 3.5.1.5 SURVEILLANCE Verify borated water volume in each accumulator is

~ 6681 gallons and~ 7645 gallons (Unit 1)

~ 6898 gallons and~ 8019 gallons (Unit 2).

Verify nitrogen cover pressure in each accumulator is

~ 611 psig and~ 685 psig.

Verify boron concentration in each accumulator is

~ 2300 ppm and ~ 2600 ppm.

Verify power is removed from each accumulator isolation valve operator control circuit when RCS pressure is> 2000 psig.

Beaver Valley Units 1 and 2 3.5.1 - 2 Accumulators 3.5.1 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

- NOTE -

Only required to be performed for affected accumulator(s)

Once within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution volume increase of ~ 1 %

of accumulator volume that is not the result of addition from the refueling water storage tank In accordance with the Surveillance Frequency Control Program Amendments292 I 179

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.5.2.1 Verify the following valves are in the listed position with power to the valve operator control circuit removed.

For Unit 1 only Number Position Function MOV-1Sl-890A Closed Low head safety injection (LHSI) to Hot Leg MOV-1Sl-890B Closed LHSI to Hot Leg MOV-1 Sl-890C Open LHSI to Cold Leg MOV-1Sl-869A Closed HHSI Pump to Hot Leg MOV-1Sl-869B Closed HHSI Pump to Hot Leg For Unit 2 only Number Position Function 2SIS*MOV8889 Closed LHSI to Hot Legs 2SIS*MOV869A Closed HHSI to Hot Leg 2SIS*MOV869B Closed HHSI to Hot Leg 2SIS*MOV841 Open HHSI to Cold Leg 2CHS*MOV8132A Open HHSI Pump Discharge Cross Connect 2CHS*MOV8132B Open HHSI Pump Discharge Cross Connect 2CHS*MOV8133A Open HHSI Pump Discharge Cross Connect 2CHS*MOV8133B Open HHSI Pump Discharge Cross Connect SR 3.5.2.2 Verify the HHSI pump minimum flow valve is open with power to the valve operator removed.

SR 3.5.2.3 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.

ECCS - Operating 3.5.2 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 Beaver Valley Units 1 and 2 3.5.2 - 2 Amendments 292 /179

SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.2.4 Verify each ECCS pump's developed head at the test flow point is greater than or equal to the required developed head.

SR 3.5.2.5 SR 3.5.2.6 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.

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

Verify, by visual inspection, that accessible regions of the ECCS containment sump suction inlet are not restricted by debris and that the accessible regions of the strainers show no evidence of structural distress or abnormal corrosion.

ECCS - Operating 3.5.2 In accordance with the I nservice Testing 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 Beaver Valley Units 1 and 2 3.5.2 - 3 Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS SR 3.5.4.1 SR 3.5.4.2 SR 3.5.4.3 SURVEILLANCE

- NOTE*

Only required to be performed when ambient air temperature is< 45°F or> 65°F.

Verify RWST borated water temperature is 2 45°F and~ 65°F.

Verify RWST borated water volume is 2 430,500 gallons (Unit 1) 2 859,248 gallons (Unit 2).

Verify RWST boron concentration is 2 2400 ppm and

~ 2600 ppm.

Beaver Valley Units 1 and 2 3.5.4 - 2 RWST 3.5.4 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 Amendments 2 9 2 / 179

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.5 Seal Injection Flow Seal Injection Flow 3.5.5 LCO 3.5.5 Reactor coolant pump seal injection flow shall be ~ 28 gpm with charging pump discharge pressure ~ 2457 psig and the seal injection flow control valve full open.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION A.

Seal injection flow not A.1 Adjust manual seal within limit.

injection throttle valves to give a flow within limit.

B.

Required Action and B.1 Be in MODE 3.

associated Completion Time not met.

AND B.2 Be in MODE 4.

SURVEILLANCE REQUIREMENTS SR 3.5.5.1 SURVEILLANCE

- NOTE -

Not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the Reactor Coolant System pressure stabilizes at

~ 2215 psig and'.":: 2255 psig.

COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 6 hours 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY Verify manual seal injection throttle valves are adjusted to give a flow of~ 28 gpm with charging pump discharge pressure z 2457 psig and the seal injection flow control valve full open.

In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.5.5 - 1 Amendments 2 9 2 / 179

Containment Air Locks 3.6.2 SURVEILLANCE REQUIREMENTS SR 3.6.2.1 SR 3.6.2.2 SURVEILLANCE

- 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.

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 Beaver Valley Units 1 and 2 3.6.2 - 4 Amendments 2 9 2 / 179

Containment Isolation Valves 3.6.3 SURVEILLANCE REQUIREMENTS SR 3.6.3.1 SR 3.6.3.2 SR 3.6.3.3 SURVEILLANCE Verify each 42-inch purge and exhaust valve is deactivated in the closed position.

- NOTE -

Valves and blind flanges in high radiation areas may be verified by use of administrative controls.

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.

- NOTE -

Valves 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 In accordance with the Surveillance Frequency Control Program Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days for valves inside containment In accordance with the Surveillance Frequency Control Program Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days Beaver Valley Units 1 and 2 3.6.3 - 4 Amendments 2 9 2 / 179

Containment Isolation Valves 3.6.3 SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.3.4 SR 3.6.3.5 SURVEILLANCE Verify the isolation time of each automatic power operated containment isolation valve that is not locked, sealed, or otherwise secured in position, and required to be closed during accident conditions, is within limits.

Verify each automatic power operated containment isolation valve that is not locked, sealed or otherwise secured in position, and required to be closed during accident conditions, actuates to the isolation position on an actual or simulated actuation signal.

FREQUENCY In accordance with the I nservice Testing Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.6.3-5 Amendments 2921179

3.6 CONTAINMENT SYSTEMS 3.6.4 Containment Pressure Containment Pressure 3.6.4 LCO 3.6.4 Containment pressure shall be~ 12.8 psia and:::; 14.2 psia.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION A.

Containment pressure not A.1 Restore containment pressure within limits.

to within limits.

B.

Required Action and B.1 Be in MODE 3.

associated Completion Time not met.

AND B.2 Be in MODE 5.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.6.4.1 Verify containment pressure is within limits.

Beaver Valley Units 1 and 2 3.6.4 - 1 COMPLETION TIME 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 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 Amendments 292 /179

Containment Air Temperature 3.6.5 3.6 CONTAINMENT SYSTEMS 3.6.5 Containment Air Temperature LCO 3.6.5 Containment average air temperature shall be 2 70°F and~ 108°F.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION A.

Containment average air A.1 Restore containment temperature not within average air temperature to limits.

within limits.

B.

Required Action and B.1 Be in MODE 3.

associated Completion Time not met.

AND B.2 Be in MODE 5.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.6.5.1 Verify containment average air temperature is within limits.

Beaver Valley Units 1 and 2 3.6.5 - 1 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 Amendments 2 9 2 I 179

3.6 CONTAINMENT SYSTEMS 3.6.6 Quench Spray (QS) System LCO 3.6.6 Two QS trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS QS System 3.6.6 CONDITION REQUIRED ACTION COMPLETION TIME A.

One QS train inoperable.

A.1 Restore QS train to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SR 3.6.6.1 SR 3.6.6.2 SR 3.6.6.3 SR 3.6.6.4 SURVEILLANCE Verify each QS 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.

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

Verify each QS 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.

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

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the I nservice Testing Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.6.6 - 1 Amendments 2 9 2 / 179

RS System 3.6.7 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.

Required Action and D.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND D.2 Be in MODE 5.

84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months E.

Three or more RS E.1 Enter LCO 3.0.3.

Immediately subsystems inoperable.

SURVEILLANCE REQUIREMENTS SR 3.6.7.1 SR 3.6.7.2 SR 3.6.7.3 SR 3.6.7.4 SURVEILLANCE Verify each RS 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.

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

Verify on an actual or simulated actuation signal(s):

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the lnservice Testing Program In accordance with the

a.

Each RS automatic valve in the flow path that is not Surveillance locked, sealed, or otherwise secured in position, Frequency actuates to the correct position, and Control Program

b.

Each RS pump starts automatically.

Verify each spray nozzle is unobstructed.

Following maintenance that results in the potential for nozzle blockage Beaver Valley Units 1 and 2 3.6.7 - 2 Amendments 292/ 179

Containment Sump pH Control System 3.6.8 3.6 CONTAINMENT SYSTEMS 3.6.8 Containment Sump pH Control System LCO 3.6.8 The Containment Sump pH Control System shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION A.

Containment Sump pH A.1 Restore Containment Control System inoperable.

Sump pH Control System to OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

associated Completion Time not met.

AND B.2 Be in MODE 5.

SURVEILLANCE REQUIREMENTS SR 3.6.8.1 SR 3.6.8.2 SURVEILLANCE Perform a visual inspection of the six sodium tetraborate storage baskets to verify the following:

a. Each storage basket is in place and intact; and,

b. Collectively contain

=: 188 cubic feet of sodium tetra borate (Unit 1)

=: 292 cubic feet of sodium tetraborate (Unit 2).

Verify that a sample from the sodium tetraborate baskets provides adequate pH adjustment of containment sump borated water.

Beaver Valley Units 1 and 2 3.6.8 - 1 COMPLETION TIME 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 6 hours 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS SR 3.7.2.1 SR 3.7.2.2 SURVEILLANCE

- NOTE -

Only required to be performed in MODES 1 and 2.

Verify the isolation time of each MSIV is within limits.

- 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.

Beaver Valley Units 1 and 2 3.7.2 - 2 MS IVs 3.7.2 FREQUENCY In accordance with the I nservice Testing Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

MFIVs and MFRVs and MFRV Bypass Valves 3.7.3 ACTIONS (continued)

CONDITION E.

Required Action and associated Completion Time not met.

E.1 AND E.2 REQUIRED ACTION Be in MODE 3.

Be in MODE4.

SURVEILLANCE REQUIREMENTS SR 3.7.3.1 SR 3.7.3.2 SURVEILLANCE Verify the isolation time of each MFIV, MFRV, and MFRV bypass valve is within limits.

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

Beaver Valley Units 1 and 2 3.7.3-2 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 lnservice Testing Program In accordance with the Surveillance Frequency Control Program Amendments 2 92 /1 79

3. 7 PLANT SYSTEMS 3.7.4 Atmospheric Dump Valves (ADVs)

LCO 3.7.4 APPLICABILITY:

For Unit 1, three ADV lines shall be OPERABLE, For Unit 2, four ADV lines shall be OPERABLE.

MODES 1, 2, and 3, AD Vs 3.7.4 MODE 4 when steam generator is relied upon for heat removal.

ACTIONS CONDITION REQUIRED ACTION A.

One required ADV line A.1 Restore required ADV line inoperable.

to OPERABLE status.

B.

Two or more required ADV B.1 Restore all but one ADV lines inoperable.

line to OPERABLE status.

C.

Required Action and C.1 Be in MODE 3.

associated Completion Time not met.

AND C.2 Be in MODE 4 without reliance upon steam generator for heat removal.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.4.1 Verify one complete cycle of each ADV.

SR 3.7.4.2 Verify one complete cycle of each ADV block valve.

Beaver Valley Units 1 and 2 3.7.4 - 1 COMPLETION TIME 7 days 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 6 hours 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 / 179

SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.4.3 SURVEILLANCE

- NOTE -

Only applicable to Unit 2.

Verify one complete cycle of each individual steam generator isolation valve associated with the Unit 2 Residual Heat Release Valve ADV line.

Beaver Valley Units 1 and 2 3.7.4 - 2 AD Vs 3.7.4 FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 2 92 fl 7 9

ACTIONS (continued)

AFW System 3.7.5 CONDITION REQUIRED ACTION COMPLETION TIME F.

Required AFW train inoperable in MODE 4.

F.1 Initiate action to restore AFW train to OPERABLE status with a capability of providing flow to the steam generator(s).

Immediately Required feedwater injection header inoperable in MODE 4.

SURVEILLANCE REQUIREMENTS SR 3.7.5.1 SR 3.7.5.2 SURVEILLANCE

- 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.

- NOTE -

Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after~ 600 psig in the steam generator.

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

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the lnservice Testing Program Beaver Valley Units 1 and 2 3.7.5 - 4 Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.5.3 SR 3.7.5.4 SURVEILLANCE

- NOTES -

1.

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.

2.

Not required to be met in MODE 4 when steam generator(s) is relied upon for heat removal.

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.

- NOTES -

1.

Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after ~ 600 psig in the steam generator.

2.

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.

3.

Not required to be met in MODE 4 when steam generator(s) is relied upon for heat removal.

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 Beaver Valley Units 1 and 2 3.7.5 - 5 Amendments 2 9 2 /179

3.7 PLANT SYSTEMS 3.7.6 Primary Plant Demineralized Water Storage Tank (PPDWST)

LCO 3.7.6 The PPDWST shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, PPDWST 3.7.6 MODE 4 when steam generator is relied upon for heat removal.

ACTIONS CONDITION REQUIRED ACTION A.

PPDWST inoperable.

A.1 Verify by administrative means OPERABILITY of backup water supply.

AND A.2 Restore PPDWST to OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

associated Completion Time not met.

AND B.2 Be in MODE 4, without reliance on steam generator for heat removal.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.6.1 Verify the PPDWST level is 2: 130,000 gallons.

Beaver Valley Units 1 and 2 3.7.6 - 1 COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter 7 days 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 24 hours FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

SURVEILLANCE REQUIREMENTS SR 3.7.7.1 SURVEILLANCE

- NOTE -

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

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

CCWSystem 3.7.7 FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.7.7 - 2 Amendments 2 9 2 / 179

ACTIONS (continued) sws 3.7.8 CONDITION REQUIRED ACTION COMPLETION TIME

- NOTE -

Only applicable in MODE 4 with inadequate SWS flow to the Component Cooling Water (CCW) heat exchangers to support the required decay heat removal needed to maintain the unit in MODE 5.

- NOTE -

LCO 3.0.3 and all other LCO Actions requiring a MODE change from MODE 4 to MODE 5 are suspended until adequate SWS flow to the CCW heat exchangers is established to maintain the unit in MODE 5.

C.

Two SWS trains inoperable.

C.1 Initiate action to restore one train of SWS to OPERABLE status.

Immediately SURVEILLANCE REQUIREMENTS SR 3.7.8.1 SR 3.7.8.2 SR 3.7.8.3 SURVEILLANCE

- NOTE -

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

Verify each SWS 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.

Verify each SWS 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.

Verify each SWS pump 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 Beaver Valley Units 1 and 2 3.7.8 - 2 Amendments 2921179

3.7 PLANT SYSTEMS 3.7.9 Ultimate Heat Sink (UHS)

LCO 3.7.9 The UHS shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION A

UHS inoperable.

A.1 Be in MODE 3.

AND A.2 Be in MODE 5.

SURVEILLANCE REQUIREMENTS SR 3.7.9.1 SR 3.7.9.2 SURVEILLANCE Verify water level of UHS is:?: 654 ft mean sea level.

Verify average water temperature of UHS is

~ 90°F (Unit 1)

~ 89°F (Unit 2).

Beaver Valley Units 1 and 2 3.7.9 - 1 UHS 3.7.9 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 In accordance with the Surveillance Frequency Control Program Amendments 2 92 /179

SURVEILLANCE REQUIREMENTS SR 3.7.10.1 SR 3.7.10.2 SR 3.7.10.3 SR 3.7.10.4 SURVEILLANCE Operate each CREVS train for :2': 15 minutes with heaters operating.

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

Verify each CREVS train actuates on an actual or simulated actuation signal.

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

CREVS 3.7.10 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the VFTP In accordance with the Surveillance Frequency Control Program In accordance with the Control Room Envelope Habitability Program Beaver Valley Units 1 and 2 3.7.10-3 Amendments 2 9 2 I 179

ACTIONS (continued)

CONDITION REQUIRED ACTION D. ----------------------------------

- NOTES-

1. Only applicable to Unit 1 during movement of irradiated fuel assemblies or fuel assemblies over irradiated fuel assemblies.

2. Only applicable to Unit 2 during movement of recently irradiated fuel assemblies and fuel assemblies over recently irradiated fuel assemblies.

Two CREACS trains D.1 Suspend movement of inoperable.

irradiated fuel assemblies and fuel assemblies over irradiated fuel assemblies.

E.

Two CREACS trains E.1 Enter LCO 3.0.3.

inoperable in MODE 1, 2, 3, or 4.

SURVEILLANCE REQUIREMENTS SR 3.7.11.1 SURVEILLANCE

- NOTE -

For Unit 1, the verification of heat removal function of CREACS is not required to support the movement of non-recently irradiated fuel.

CREA CS 3.7.11 COMPLETION TIME Immediately Immediately FREQUENCY Verify each CREACS train has the capability to remove the required heat load and purge the control room atmosphere at the required flow rate.

In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.7.11-3 Amendments 2 9 2 '1 7 9

SURVEILLANCE REQUIREMENTS SR 3.7.12.1 SR 3.7.12.2 SR 3.7.12.3 SURVEILLANCE Verify required SLCRS train is in operation.

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

- NOTE -

Only required to be met during movement of recently irradiated fuel assemblies within the fuel storage pool and during movement of fuel assemblies over recently irradiated fuel assemblies within the fuel storage pool.

Verify the required SLCRS train can maintain the fuel storage pool area at a negative pressure of;::: 0.125 (Unit 1 ), ;::: 0.05 (Unit 2) inches water gauge relative to atmospheric pressure during system operation.

SLCRS 3.7.12 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the VFTP In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.7.12-2 Amendments 2 9 2 I 179

3.7 PLANT SYSTEMS 3.7.13 Secondary Specific Activity Secondary Specific Activity 3.7.13 LCO 3. 7.13 The specific activity of the secondary coolant shall be :::: 0.10 µCi/gm DOSE EQUIVALENT 1-131.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION A.

Specific activity not within A.1 limit.

AND A.2 SURVEILLANCE REQUIREMENTS Be in MODE 3.

Be in MODE 5.

SURVEILLANCE SR 3.7.13.1 Verify the specific activity of the secondary coolant is

0.10 µCi/gm DOSE EQUIVALENT 1-131.

Beaver Valley Units 1 and 2 3.7.13-1 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 Amendments 2 9 2 /179

Fuel Storage Pool Water Level 3.7.15 3.7 PLANT SYSTEMS 3.7.15 Fuel Storage Pool Water Level LCO 3.7.15 APPLICABILITY:

ACTIONS The fuel storage pool water level shall be 2 23 ft over the top of irradiated fuel assemblies seated in the storage racks.

During movement of irradiated fuel assemblies in the fuel storage pool, During movement of fuel assemblies over irradiated fuel assemblies in the fuel storage pool.

CONDITION REQUIRED ACTION COMPLETION TIME A.

Fuel storage pool water level not within limit.

- NOTE -

LCO 3.0.3 is not applicable.

A.1 Suspend movement of irradiated fuel assemblies in the fuel storage pool.

Immediately A.2 Suspend movement of fuel Immediately assemblies over irradiated fuel assemblies in the fuel storage pool.

SURVEILLANCE REQUIREMENTS SR 3.7.15.1 SURVEILLANCE Verify the fuel storage pool water level is 2 23 ft above the top of the irradiated fuel assemblies seated in the storage racks.

FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.7.15-1 Amendments 2 9 2 I 179

Fuel Storage Pool Boron Concentration 3.7.16 SURVEILLANCE REQUIREMENTS SR 3.7.16.1 SURVEILLANCE FREQUENCY Verify the fuel storage pool boron concentration is within In accordance limit.

with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.7.16-2 Amendments 2 9 2 / 179

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.1 SR 3.8.1.2 SR 3.8.1.3 SURVEILLANCE Verify correct breaker alignment and indicated power availability for each required offsite circuit.

- NOTES-

1.

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

2.

A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.

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

2'. 4106 V and~ 4368 V (Unit 1)

2'. 3994 V and ~ 4368 V (Unit 2),

and frequency

2'. 58.8 Hz and ~ 61.2 Hz (Unit 1)

2'. 59.9 Hz and ~ 60.3 Hz (Unit 2).

- NOTES -

1.

DG loadings may include gradual loading as recommended by the manufacturer.

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.

Verify each DG is synchronized and loaded and operates for :2'. 60 minutes at a load

2'. 2340 kW and ~ 2600 kW (Unit 1)

2'. 3814 kW and~ 4238 kW (Unit 2).

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 Beaver Valley Units 1 and 2 3.8.1 - 5 Amendments 2 9 2 I 179

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.4.1 SR 3.8.1.4.2 SR 3.8.1.5.1 SR 3.8.1.5.2 SR 3.8.1.6 SURVEILLANCE

- NOTE -

Only applicable to Unit 1.

Verify each DG's day and engine mounted tanks contain a combined total of;::.: 900 gal of fuel oil.

- NOTE -

Only applicable to Unit 2.

FREQUENCY In accordance with the Surveillance Frequency Control Program Verify each DG's day tank contains;::.: 350 gal of fuel oil.

In accordance with the Surveillance Frequency Control Program

- NOTE -

Only applicable to Unit 1.

Check and remove accumulated water from each day tank and engine mounted tank.

- NOTE -

Only applicable to Unit 2.

Check and remove accumulated water from each day tank.

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

In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.1 - 6 Amendments 292/ 179

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.7 SR 3.8.1.8 SURVEILLANCE Verify automatic and manual transfer of AC power sources from the unit circuit to system offsite circuit.

- NOTES -

1.

This Surveillance shall not normally be performed in MODE 1 or 2. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

2.

If performed with the DG synchronized with offsite power, it shall be performed at a power factor s 0.89. 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 rejects a load greater than or equal to its associated single largest post-accident load, and:

a.

Following load rejection, the frequency is s 66.2 Hz (Unit 1) s 64.4 Hz (Unit 2),

b.

Within 3 seconds following load rejection, the voltage is 2': 4106 V and~ 4368 V (Unit 1)

~ 3994 V and s 4368 V (Unit 2), and

c.

Within 4 seconds following load rejection, the frequency is 2': 58.8 Hz ands 61.2 Hz (Unit 1)

~ 59.9 Hz and s 60.3 Hz (Unit 2).

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.1 - 7 Amendments 292 1179

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SR 3.8.1.9 SURVEILLANCE

- NOTE -

This Surveillance shall not normally be performed in MODE 1 or 2. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify each DG's automatic trips are bypassed on actual or simulated loss of voltage signal on the emergency bus except:

a.

Engine overspeed,

b.

Generator differential current, and

c.

Generator overcurrent.

a.

Engine overspeed,

b.

Generator differential current,

c.

Backup phase fault detection, and

d.

Generator overexcitation.

FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.1 - 8 Amendments 292 /l 79

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SR 3.8.1.10 SURVEILLANCE

- NOTES -

1.

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

2.

This Surveillance shall not normally be performed in MODE 1 or 2. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

3.

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

~ 0.89. 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::'.': 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months s:

a.

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

'.': 2750 kW and ~ 2850 kW (Unit 1)

'.': 4238 kW and ~ 4535 kW (Unit 2), and

b.

For the remaining hours of the test loaded

'.': 2340 kW and~ 2600 kW (Unit 1)

'.': 3814 kW and~ 4238 kW (Unit 2).

FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.1-9 Amendments 2 9 2 I 179

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.11 SR 3.8.1.12 SURVEILLANCE

- NOTE-This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR Verify each DG:

a.

Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power,

b.

Transfers loads to offsite power source, and c.1 Proceeds through its shutdown sequence (Unit 1 ),

c.2 Returns to ready-to-load operation (Unit 2).

- NOTES -

1.

Only applicable to Unit 2.

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. Credit may be taken for unplanned events that satisfy this SR.

Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ESF actuation signal overrides the test mode by returning DG to ready-to-load operation.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.1 - 10 Amendments 2 9 2 I 179

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SR 3.8.1.13 SURVEILLANCE

- NOTE -

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify each automatic load sequence time is within

+/- 10% of required value.

FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.1 - 11 Amendments 2 9 2 /179

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SR 3.8.1.14 SURVEILLANCE

- NOTES -

1.

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

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. Credit may be taken for unplanned events that satisfy this SR.

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

a.

De-energization of emergency buses,

b.

Load shedding from emergency buses, and

c.

DG auto-starts from standby condition and:

1.

Energizes permanently connected loads in

~ 1 O seconds,

2.

Energizes auto-connected emergency loads through load sequencer,

3.

Achieves steady state voltage 2 4106 V and~ 4368 V (Unit 1) 2 3994 V and ::::: 4368 V (Unit 2),

4.

Achieves steady state frequency 2 60.0 Hz and ~ 60.4 Hz (Unit 1) 2 59.9 Hz and ::::: 60.3 Hz (Unit 2), and

5.

Supplies permanently connected and auto-connected emergency loads for 2 5 minutes.

FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.1 - 12 Amendments 2 92 / 179

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SR 3.8.1.15 SURVEILLANCE

- NOTES-

1. Only applicable to Unit 2.

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

Verify when started simultaneously from standby condition, each DG achieves:

a.

In:-::;; 10 seconds, voltage ;:o: 3994 V and frequency

o

59.9 Hz and

b.

Steady state voltage ;:o: 3994 V and :-::;; 4368 V, and frequency ;:o: 59.9 Hz and :-::;; 60.3 Hz.

FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.1 - 13 Amendments 2 9 2 / 179

Diesel Fuel Oil, Lube Oil, and Starting Air 3.8.3 ACTIONS (continued)

CONDITION F.

Required Action and associated Completion Time not met.

One or more DGs with diesel fuel oil, lube oil, or starting air subsystem not within limits for reasons other than Condition A, B, C, D, or E.

F.1 SURVEILLANCE REQUIREMENTS REQUIRED ACTION Declare associated DG inoperable.

SURVEILLANCE SR 3.8.3.1 SR 3.8.3.2 SR 3.8.3.3 SR 3.8.3.4 SR 3.8.3.5 Verify each fuel oil storage tank contains 2 17,500 gal of fuel oil (Unit 1) 2 53,225 gal of fuel oil (Unit 2).

Verify lubricating oil inventory is 2 330 gal.

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.

Verify DG air start receiver pressure is 2 165 psig (Unit 1) 2 380 psig (Unit 2).

Check for and remove accumulated water from each fuel oil storage tank.

Beaver Valley Units 1 and 2 3.8.3-2 COMPLETION TIME Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Diesel Fuel Oil Testing Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS SR 3.8.4.1 SR 3.8.4.2 SR 3.8.4.3 SURVEILLANCE Verify battery terminal voltage is greater than or equal to the minimum established float voltage.

Verify each battery charger supplies ~ 100 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 largest combined demands of the various continuous steady state loads, after a battery discharge to the bounding design basis event discharge state.

- 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 be performed in MODE 1, 2, 3, or 4. Credit may be taken for unplanned events that satisfy this SR.

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 Beaver Valley Units 1 and 2 3.8.4 - 2 Amendments292 /179

SURVEILLANCE REQUIREMENTS SR 3.8.6.1 SR 3.8.6.2 SR 3.8.6.3 SR 3.8.6.4 SR 3.8.6.5 SURVEILLANCE

- NOTE -

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

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

Verify each battery pilot cell voltage is~ 2.07 V.

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

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

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 Beaver Valley Units 1 and 2 3.8.6-3 Amendments 2 9 2 /179

SURVEILLANCE REQUIREMENTS continued SR 3.8.6.6 SURVEILLANCE

- NOTE -

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

Verify battery capacity is ~ 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 18 months when battery shows degradation, or has reached 85%

of the expected life Beaver Valley Units 1 and 2 3.8.6-4 Amendments 292 /179

Inverters - Operating 3.8.7 SURVEILLANCE REQUIREMENTS SR 3.8.7.1 SURVEILLANCE FREQUENCY Verify correct inverter voltage and alignment to required In accordance AC vital buses.

with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.8.7 - 2 Amendments 2 9 2 / 179

ACTIONS (continued)

CONDITION A.2.3 REQUIRED ACTION

- NOTE -

Only applicable to Unit 2.

Inverters - Shutdown 3.8.8 COMPLETION TIME Suspend movement of Immediately recently irradiated fuel assemblies and movement of fuel assemblies over recently irradiated fuel assemblies.

A.2.4 Suspend operations Immediately involving positive reactivity additions that could result in loss of required SOM or boron concentration.

A.2.5 Initiate action to restore required inverters to OPERABLE status.

SURVEILLANCE REQUIREMENTS SR 3.8.8.1 SURVEILLANCE Verify correct inverter voltage and alignments to required AC vital buses.

Beaver Valley Units 1 and 2 3.8.8-2 Immediately FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 2 92 /1 79

Distribution Systems - Operating 3.8.9 ACTIONS (continued)

CONDITION REQUIRED ACTION C.

One or more DC electrical C. 1 Restore DC electrical power distribution power distribution subsystems inoperable.

subsystem(s) to OPERABLE status.

D.

Required Action and D.1 Be in MODE 3.

associated Completion Time not met.

AND D.2 Be in MODE 5.

E.

Two or more electrical E.1 Enter LCO 3.0.3.

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

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.9.1 Verify correct breaker alignments and voltage to required AC, DC, and AC vital bus electrical power distribution subsystems.

Beaver Valley Units 1 and 2 3.8.9-2 COMPLETION TIME 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months AND 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months from discovery of failure to meet LCO 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 Amendments 2 9 2 / 179

ACTIONS (continued)

CONDITION Distribution Systems - Shutdown 3.8.10 REQUIRED ACTION COMPLETION TIME A.2.3

- NOTE -

Only applicable to Unit 2.

Suspend movement of Immediately recently irradiated fuel assemblies and movement of fuel assemblies over recently irradiated fuel assemblies.

A.2.4 Suspend operations Immediately involving positive reactivity additions that could result in loss of required SOM or boron concentration.

A.2.5 Initiate actions to restore Immediately required AC, DC, and AC vital bus electrical power distribution subsystems to OPERABLE status.

A.2.6 Declare associated required residual heat removal subsystem(s) inoperable and not in operation.

Immediately SURVEILLANCE REQUIREMENTS SR 3.8.10.1 SURVEILLANCE Verify correct breaker alignments and voltage to required AC, DC, and AC vital bus electrical power distribution subsystems.

Beaver Valley Units 1 and 2 3.8.10- 2 FREQUENCY In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 /179

Boron Concentration 3.9.1 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration LCO 3.9.1 APPLICABILITY:

ACTIONS Boron concentrations of the Reactor Coolant System (RCS}, the refueling canal, and the refueling cavity shall be maintained within the limit specified in the COLR.

MODE6.

- NOTE -

Only applicable to the refueling canal and refueling cavity when connected to the RCS.

CONDITION REQUIRED ACTION COMPLETION TIME A.

Boron concentration not A.1 Suspend CORE AL TERA TIONS.

Immediately within limit.

A.2 Suspend positive reactivity Immediately additions.

AND A.3 Initiate action to restore boron concentration to within limit.

Immediately SURVEILLANCE REQUIREMENTS SR 3.9.1.1 SURVEILLANCE FREQUENCY Verify boron concentration is within the limit specified In accordance in the COLR.

with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.9.1 - 1 Amendments 2 9 2 / 179

SURVEILLANCE REQUIREMENTS SR 3.9.2.1 SR 3.9.2.2 SURVEILLANCE Perform CHANNEL CHECK.

- NOTE -

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

Beaver Valley Units 1 and 2 3.9.2 - 2 Nuclear Instrumentation 3.9.2 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendments 2 9 2 I 179

Containment Penetrations 3.9.3 SURVEILLANCE REQUIREMENTS SR 3.9.3.1 SR 3.9.3.2 SR 3.9.3.3 SR 3.9.3.4 SURVEILLANCE

- NOTES -

1.

Only applicable to Unit 2.

2.

Only required to be met when operating the Containment Purge and Exhaust System in accordance with LCO 3.9.3.c.2.

Verify the containment purge exhaust flow rate is

~ 7500 cfm.

Verify each required containment penetration is in the required status.

- NOTES-

1.

Only applicable to Unit 2.

2.

Not required to be met for containment purge and exhaust valve(s) in penetrations closed to comply with LCO 3.9.3.c.1.

Verify each required containment purge and exhaust valve actuates to the isolation position on an actual or simulated actuation signal.

- NOTES -

1.

Only applicable to Unit 2.

2.

Not required to be met for containment purge and exhaust valve(s) in penetrations closed to comply with LCO 3.9.3.c.1.

Verify the isolation time of each containment purge and exhaust valve is within limit.

Beaver Valley Units 1 and 2 3.9.3 - 2 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 Amendments 2 9 2 /179

RHR and Coolant Circulation - High Water Level 3.9.4 SURVEILLANCE REQUIREMENTS SR 3.9.4.1 SR 3.9.4.2 SURVEILLANCE

- NOTE -

Only required to be met prior to the start of and during operations that cause the introduction of coolant into the RCS with boron concentration less than that required to meet the minimum required boron concentration of LCO 3.9.1.

FREQUENCY Verify one RHR loop is circulating reactor coolant at In accordance a flow rate of 2:: 3000 gpm.

with the Surveillance Frequency Control Program Verify one RHR loop is in operation.

In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.9.4 - 3 Amendments 2 9 2 /179

RHR and Coolant Circulation - Low Water Level 3.9.5 SURVEILLANCE REQUIREMENTS SR 3.9.5.1 SR 3.9.5.2 SR 3.9.5.3 SR 3.9.5.4 SURVEILLANCE

- NOTE -

Only required to be met prior to the start of and during operations that cause the introduction of coolant into the RCS with boron concentration less than that required to meet the minimum required boron concentration of LCO 3.9.1.

Verify one RHR loop is circulating reactor coolant at a flow rate of~ 3000 gpm.

- NOTE -

Only required to be met when RCS water level is

> three feet below the reactor vessel flange.

Verify one RHR loop is circulating reactor coolant at a flow rate of~ 1000 gpm.

Verify one RHR loop is in operation.

- NOTE -

Not 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 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 In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.9.5 - 3 Amendments 2 9 2 /179

Refueling Cavity Water Level 3.9.6 3.9 REFUELING OPERATIONS 3.9.6 Refueling Cavity Water Level LCO 3.9.6 APPLICABILITY:

ACTIONS Refueling cavity water level shall be maintained 2 23 ft above the top of reactor vessel flange.

During movement of irradiated fuel assemblies within containment, During movement of fuel assemblies over irradiated fuel assemblies within the containment.

CONDITION REQUIRED ACTION COMPLETION TIME A.

Refueling cavity water level not within limit.

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

Immediately A.2 Suspend movement of fuel Immediately assemblies over irradiated fuel assemblies within containment.

SURVEILLANCE REQUIREMENTS SR 3.9.6.1 SURVEILLANCE Verify refueling cavity water level is 2 23 ft above the top of reactor vessel flange.

FREQUENCY In accordance with the Surveillance Frequency Control Program Beaver Valley Units 1 and 2 3.9.6 - 1 Amendments 2 9 2 / 179

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Control Room Envelope Habitability Program (continued) 5.5.15

c.

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

d.

Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by one train of the CREVS, operating at the flow rate required by the VFTP, at a Frequency of 18 months on a STAGGERED TEST BASIS. The results shall be trended and used as part of the periodic assessment of the CRE boundary.

e.

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

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

Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.

f.

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

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 Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.

Beaver Valley Units 1 and 2 5.5-21 Amendments 2 9 21 179

5.5 Programs and Manuals 5.5.15 Surveillance Frequency Control Program (continued)

Programs and Manuals 5.5

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.

Beaver Valley Units 1 and 2 5.5 - 22 Amendments292 I 179 I

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 FIRSTENERGY NUCLEAR OPERATING COMPANY FIRSTENERGY NUCLEAR GENERATION LLC OHIO EDISON COMPANY THE TOLEDO EDISON COMPANY DOCKET NO. 50-412 BEAVER VALLEY POWER STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No.179 Renewed License No. NPF-73

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by FirstEnergy Nuclear Operating Company (FENOC)* acting on its own behalf and as agent for FirstEnergy Nuclear Generation, LLC, Ohio Edison Company, and The Toledo Edison Company (the licensees), dated October 18, 2013, as supplemented by letters dated June 26, 2014, September 21, 2014, and February 4, 2015, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's 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 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 rules and 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.

FENOC is authorized to act as agent for FirstEnergy Nuclear Generation, LLC, Ohio Edison Company, and The Toledo Edison Company and has exclusive responsibility and control over the physical construction, operation, and maintenance of the facility.

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. NPF-73 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 179, and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto are hereby incorporated in the license. FENOC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3.

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

FOR THE NUCLEAR REGULATORY COMMISSION

,,-/ / *~Jf?d_.

Douglas A. Broaddus, Chief Plant Licensing Branch 1-2

Attachment:

Changes to the Technical Specifications and Renewed Facility Operating License Date of Issuance: March 6, 2015 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

ATTACHMENT TO LICENSE AMENDMENT NO. 179 RENEWED FACILITY OPERATING LICENSE NO. NPF-73 DOCKET NO. 50-412 Replace the following page of the Renewed Facility Operating License with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove Page 4 Page 4 Beaver Valley Power Station Units 1 and 2 share a common Appendix A, Technical Specifications. As such, the replacement pages listed in the attachment to License Amendment No. 292 will also be applicable for Amendment No. 179.

(b)

Further, the licensees are also required to notify the NRC in writing prior to any change in: (i) the term or conditions of any lease agreements executed as part of these transactions; (ii) the BVPS Operating Agreement, (iii) the existing property insurance coverage for BVPS Unit 2, and (iv) any action by a lessor or others that may have adverse effect on the safe operation of the facility.

C.

This renewed operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations set forth in 10 CFR Chapter 1 and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1)

Maximum Power Level FENOC is authorized to operate the facility at a steady state reactor core power level of 2900 megawatts thermal.

(2)

Technical Specifications Beaver Valley Unit 2 The Technical Specifications contained in Appendix A, as revised through Amendment No. 179, and the Environmental Protection Plan contained in Appendix 8, both of which are attached hereto are hereby incorporated in the license. FENOC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Amendment No. 179 Renewed Operating License NPF-73

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NOS. 292 AND 179 TO RENEWED FACILITY OPERATING LICENSE NOS. DPR-66 AND NPF-73 FIRSTENERGY NUCLEAR OPERATING COMPANY FIRSTENERGY NUCLEAR GENERATION, LLC OHIO EDISON COMPANY THE TOLEDO EDISON COMPANY BEAVER VALLEY POWER STATION, UNIT NOS. 1 AND 2 DOCKET NOS. 50-334 AND 50-412

1.0 INTRODUCTION

By application dated October 18, 2013 (Reference 1 ), as supplemented by letters dated June 26, 2014 (Reference 2), September 21, 2014 (Reference 3), and February 4, 2015 (Reference

4) the FirstEnergy Nuclear Operating Company, et al. (the licensee), requested changes to the Technical Specifications (TSs) for Beaver Valley Power Station, Unit Nos. 1 and 2 (BVPS-1 and 2). The supplements dated June 26, 2014, September 21, 2014, and February 4, 2015, did not expand the scope of the application as originally noticed, and did not change the staff's original proposed no significant hazards consideration determination as published in the Federal Register (FR) on January 21, 2014 (79 FR 3416).

The requested change is the adoption of Nuclear Regulatory Commission (NRC)-approved TS Task Force Traveler (TSTF)--425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control-[Risk-lnformed Technical Specification Task Force] RITSTF Initiative 5b" (Reference 5). When implemented, TSTF--425, Revision 3 (Rev. 3), relocates most periodic frequencies of TS surveillances to a licensee-controlled program, the Surveillance Frequency Control Program (SFCP), and provides requirements for the new program in the Administrative Controls section of the TS. All surveillance frequencies can be relocated except:

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~ 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., "drywell to suppression chamber differential pressure decrease").

A new program is added to the Administrative Controls of TS Section 5, Administrative Controls, as Specification 5.5.15, "Surveillance Frequency Control Program." The Surveillance Frequency Control Program (SFCP) describes the requirements for the program to control changes to the relocated surveillance frequencies. The TS Bases for each of the affected surveillance requirements are revised to state that the frequency is set in accordance with the SFCP. Some surveillance requirements Bases do not contain a discussion of the frequency. In these cases, the Bases describing the current frequency were added to maintain consistency with the Bases for similar surveillances. These instances are noted in the markup along with the source of the text. The proposed licensee changes to the Administrative Controls of the TS to incorporate the SFCP include a specific reference to Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specifications Initiative 5B, Risk-Informed Method for Control of Surveillance Frequencies," Revision 1 (Reference 6) as the basis for making any changes to the surveillance frequencies once they are relocated out of the TS.

The NRG staff approved NEI 04-10, Revision 1, by letter dated September 19, 2007 (Reference 7), as acceptable for referencing in licensing actions to the extent specified and under the limitations delineated in NEI 04-10, and the safety evaluation (SE) providing the basis for NRG acceptance of NEI 04-10.

The licensee's application dated October 18, 2013, provided revised TS Bases pages to be implemented with the associated TS changes. These pages were provided for information only and will be revised in accordance with the TS Bases Control Program.

2.0 REGULATORY EVALUATION

In the "Final Policy Statement: Technical Specifications for Nuclear Power Plants" published in the FR (Reference 8) the NRG addressed the use of Probabilistic Safety Analysis (PSA, currently referred to as Probabilistic Risk Assessment (PRA)) in STS. In this 1993 FR publication, the NRG states, in part, that:

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 10 CFR 50. 36]

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 NRG provided additional detail concerning the use of PRA in the "Final Policy Statement: Use of Probabilistic Risk Assessment in Nuclear Regulatory Activities," published in the FR (Reference 9). In this FR publication, the NRG 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 NRG 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.

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 NRG 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 Title 10 of the Code of Federal Regulations ( 10 CFR) 50.109 (Backfit Rule). Appropriate procedures for including PRA in the process 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.

In 10 CFR 50.36, "Technical Specifications," the NRC established its regulatory requirements related to the content of TS. Pursuant to 10 CFR 50. 36, TS are required to include items in the following five specific categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation; (3) surveillance requirements; (4) design features; and (5) administrative controls.

As stated in 10 CFR 50.36(c)(3):

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.

These categories will remain in TS. The new TS SFCP provides the necessary administrative controls to require that surveillances 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.

Changes to surveillance frequencies in the SFCP are made using the methodology contained in NEI 04-10, including qualitative considerations, results of risk analyses, sensitivity studies and any bounding analyses, and recommended monitoring of structures, systems, and components (SSCs), and required to be documented.

Licensees are required by TS to perform surveillance test, calibration, or inspection on specific safety-related system equipment (e.g., reactivity control, power distribution, electrical, and instrumentation) to verify system operability. Surveillance frequencies, currently identified in TS, 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 provides a way to establish risk-informed surveillance frequencies that complement the deterministic approach and support the NRC's traditional defense-in-depth philosophy.

The licensee's SFCP ensures that surveillance requirements specified in the TS are performed at intervals sufficient to assure the above regulatory requirements are met. Existing regulatory requirements, such as 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and 10 CFR 50 Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants" (corrective action program), require licensee monitoring of surveillance test failures and implementing corrective actions to address such failures. One of these actions may be to consider increasing the frequency at which a surveillance test is performed. In addition, the SFCP implementation guidance in NEI 04-10 requires monitoring the performance of structures, systems, and components (SSCs) for which surveillance frequencies are decreased to assure reduced testing does not adversely impact the SSCs. These requirements, and the monitoring required by NEI 04-10, 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.

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," (Reference 10),

describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed permanent licensing-basis changes by considering engineering issues and applying risk insights. This regulatory guide 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," (Reference 11 ), describes an acceptable risk-informed approach specifically for assessing proposed permanent TS changes in allowed outage times. This regulatory guide also provides risk acceptance guidelines for evaluating the results of such assessments.

RG 1.177 identifies a three-tiered approach for the licensees evaluation of the risk associated with a proposed completion time (CT) TS change, as discussed below.

Tier 1 assesses the risk impact of the proposed change in accordance with acceptance guidelines consistent with the Commission's Safety Goal Policy Statement, as documented in RG 1.17 4 and RG 1.177. The first tier assesses the impact on operational plant risk based on the change in core damage frequency (~CDF) and change in large early release frequency (~LERF). It also evaluates plant risk while equipment covered by the proposed CT is out-of-service, as represented by incremental conditional core damage probability and incremental conditional large early release probability. Tier 1 also addresses PRA quality, including the technical adequacy of the licensee's plant-specific PRA for the subject application. Cumulative risk of the present TS change, in light of past related applications or additional applications under review, are also considered along with uncertainty/sensitivity analysis with respect to the assumptions related to the proposed TS change.

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

Tier 3 addresses the licensee's overall configuration risk management program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and appropriate compensatory measures are taken to avoid risk significant configurations that may not have been considered when the Tier 2 evaluation was performed. Compared with Tier 2, Tier 3 provides additional coverage to ensure risk-significant plant equipment outage configurations are identified in a timely manner and that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity over extended periods of plant operation. Tier 3 guidance can be satisfied by the Maintenance Rule (10 CFR 50.65(a)(4)), which requires a licensee to assess and manage the increase in risk that may result from activities such as surveillance testing and corrective and preventive maintenance, subject to the guidance provided in RG 1.177, Section 2. 3. 7.1, and the adequacy of the licensee's program and PRA model for this application. The CRMP is to ensure that equipment removed from service prior to or during the proposed extended CT will be appropriately assessed from a risk perspective.

RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," (Reference 12), 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 decision making for light water-reactors.

3.0 TECHNICAL EVALUATION

The licensee's adoption of TSTF-425 for BVPS provides for administrative relocation of applicable surveillance frequencies, and provides for the addition of the SFCP to the administrative controls of the TS. TSTF-425 also requires the application of NEI 04-10 for any changes to surveillance frequencies within the SFCP. The licensee's application for the changes proposed in TSTF-425 included documentation regarding the PRA technical adequacy consistent with the requirements of RG 1.200. In accordance with NEI 04-10, PRA methods are used in combination with plant performance data and other considerations, to identify and justify modifications to the surveillance frequencies of equipment at nuclear power plants. This is in accordance with guidance provided in RG 1.17 4 and RG 1.177 in support of changes to surveillance test intervals (STI).

3.1 RG 1.177 Five Key Safety Principles RG 1.177 identifies five key safety principles required for risk-informed changes to TS. Each of these principles is addressed by the industry methodology document, NEI 04-10.

3. 1. 1 The Proposed Change Meets Current Regulations The regulations in 10 CFR 50.36(c)(3) provide that TSs will 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." NEI 04-10 provides guidance for relocating the surveillance frequencies from the TSs to a licensee-controlled program by providing an NRG-approved methodology for control of the surveillance frequencies. The surveillances themselves would remain in the TSs, as required by 10 CFR 50.36(c)(3).

This change is consistent with other NRG-approved TS changes in which the surveillance frequencies are relocated to licensee-controlled documents, such as surveillances performed in accordance with the In-service Testing Program or the Primary Containment Leakage Rate Testing Program. Thus, this proposed change meets the first key safety principle of RG 1.177 by complying with current regulations.

3.1.2 The Proposed Change Is Consistent With the Defense-in-Depth Philosophy Consistency with the defense-in-depth philosophy, the second key safety principle of RG 1.177, 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 are preserved, and the potential for the introduction of new common cause failure 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.

TSTF-425 requires the application of NEI 04-10 for any changes to surveillance frequencies within the SFCP. NEI 04-10 uses both the core damage frequency (CDF) and the large early release frequency (LERF) metrics to evaluate the impact of proposed changes to surveillance frequencies. The guidance of RG 1.17 4 and RG 1.177 for changes to CDF and LERF is achieved by evaluation using a comprehensive risk analysis, which assesses the impact of proposed changes including contributions from human errors and common cause failures.

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 common cause failures. Both the quantitative risk analysis and the qualitative considerations assure a reasonable balance of defense-in-depth is maintained to ensure protection of public health and safety, satisfying the second key safety principle of RG 1.177.

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 with the principle 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 plant licensing basis (including the Updated Final Safety Analysis Report and bases to TS), since 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.

Thus, safety margins are maintained by the proposed methodology, and the third key safety principle of RG 1.177 is satisfied.

3.1.4 When Proposed Changes Result in an Increase in Core Damage Frequency or Risk, the Increases Should Be Small and Consistent With the Intent of the Commission's Safety Goal Policy Statement RG 1. 177 provides a framework for evaluating the risk impact of proposed changes to surveillance frequencies. This requires the 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. TSTF-425 requires application of NEI 04-10 in the SFCP. NEI 04-10 satisfies the intent of RG 1.177 requirements for evaluating the change in risk, and for assuring that such changes are small.

3.1.4.1 Quality of the PRA The quality of the BVPS PRA is compatible with the safety implications of the proposed TS change and the role the PRA plays in justifying the change. That is, the more the potential 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 quality of the PRA.

The licensee used RG 1.200 to address the technical adequacy of the BVPS PRA. RG 1.200 is NRC's developed regulatory guidance, which endorses with comments and qualifications the use of the American Society of Mechanical Engineers (ASME) RA-Sb-2005, "Addenda to ASME RA-S-2002 Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications," (Reference 13), NEI 00-02, "PRA Peer Review Process Guidelines," (Reference

14) and NEI 05-04, "Process for Performing Follow-On PRA Peer Reviews Using the ASME PRA Standard" (Reference 15). An independent Peer Review of their PRA model was performed by Westinghouse Owners Group in July 2002 using the NEI 00-02 guidance. The licensee then performed a self-assessment to the PRA standard, as clarified by RG 1.200 Revision 1 in 2007, following their 2006 model revision. In 2007, the licensee performed a focused scope peer review against the Human Reliability Analysis (HRA) methodology that was incorporated into the 2006 model revision using the ASME Standard, as clarified by RG 1.200 Rev. 1. Due to an upgrade of the internal flooding model in 2010, the licensee performed a focused-scope peer review to the ASME Standard, as clarified by RG 1.200 Rev. 2 (Reference 16). The licensee has performed an assessment of the PRA models used to support the SFCP against the requirements of RG 1.200 to assure that the PRA models are capable of determining the change in risk due to changes to surveillance frequencies of SSCs, using plant-specific data and models. Capability Category II of ASME RA-Sb-2005, and in the case of the internal flooding model, ASME RA-Sa-2009, is applied as the standard, and any identified deficiencies to those requirements are assessed further to determine any impacts to proposed changes to surveillance frequencies, including the use of sensitivity studies where appropriate.

The staff reviewed the peer review team assessment of the BVPS PRA models that do not conform to capability category II of the ASME PRA standard Supporting Requirements (SRs)

(Table 2 of Enclosures Band C of Reference 1). The staff's assessment of these open Findings and Observations (F&Os) and the licensee's resolutions concluded that they are addressed and dispositioned for each surveillance frequency evaluation per the NEI 04-10 guidance, as discussed below.

HR-81-01: A generic term was used to account for all misalignment Human Error Probabilities (HEPs) without regard for procedural or operation failure barriers (e.g., peer checks and independent verification). The licensee resolved this by evaluating testing and maintenance procedures for these errors and analyzing them in the Electric Power Research Institute (EPRI)

HRA calculator to develop specific HEPs. The staff finds that the licensee's resolution sufficiently addresses the F&O since it accounts for plant-specific testing and maintenance.

HR-PR-003: The method that was used to quantify the pre-initiator misalignment errors relied on the generic Error of Omission rate that does not reflect any detailed assessment of the HEPs. The licensee resolved this by quantifying the pre-initiators using the Technique for Human Error Rate Prediction (THERP) methodology and their process now considers the plant-specific written procedures, administration controls, and man-machine interface. This F&O covered a number of SRs in the ASME standard that covered pre-initiator human failure events and documentation of human reliability analysis. The staff finds that the resolution sufficiently addresses the F&O since it was resolved using plant-specific information and updated documentation.

LE-C2a-01: This Supporting Requirement was assigned a Capability Category I because BVPS-2 does not model operator actions post core damage. This F&O covers a number of SRs that include identification of accident progression analyses that would result in a large, early release. The licensee reviewed the suggested source of potential operator actions to include in their level 2 PRA model for BVPS-1, and added the Level 2 Operator Action to restore feedwater to a dry steam generator to the PRA model. The staff finds that while the modeling of generator actions is limited, these modeling considerations can be addressed per the guidance in NEI 04-10.

LE-C10-01: This F&O was related to the Steam Generator Tube Rupture and Containment Bypass analysis, which did not take credit for scrubbing. The licensee resolved this F&O by adding a discussion to give credit for steam generator tube rupture (SGTR) scrubbing and the basis for the decontamination factor; therefore, the staff finds that the F&O has been addressed adequately and modeling uncertainty will be addressed per the guidance in NEI 04-10.

LE-05-01: This F&O was created because the Thermal Induced Steam Generator Tube Rupture (Tl-SGTR) analysis was based on a 1995 report that the peer review team considered "too optimistic." The peer review team suggested implementing WCAP 16341, "Simplified LERF Model," and characterizing the uncertainties based on that latest EPRI, Pressurized Water Reactor Owners Group (PWROG), and NRC interactions. The licensee has documented the Tl-SGTR methodology, and the uncertainties will be addressed per the guidance in NEI 04-10.

LE-E4-01: This F&O was created because the LERF evaluation only used point estimates for each top event with no uncertainty estimates or uncertainty propagation. BVPS stated that their Level 2 phenomena split fraction distributions, the Unit 1 plant specific Level 2 phenomena distribution along with the mean, median, 5th percentile, and 95th percentile, and the associated discussions on how these distributions were developed is provided in the Level 2 LERF Analysis notebook. The staff finds that the information presented by the licensee for determining the uncertainty in the LERF analysis sufficiently addresses the F&O.

SY-81-01: This F&O indicated that there was no information supporting the BVPS use of NUREG/CR-5497, "Common Cause Failure Parameter Estimation," for their common cause failure data update. Instead, the peer review team believed that the licensee used generic data, based on a Pickard, Lowe, and Garrick (PLG) database from around 1989. The licensee stated that they used WCAP-16672-P for updated Common Cause Failure (CCF) data. In RAI 4 of letter dated June 3, 2014 (Reference 17), the NRC staff requested the points of deviation between the WCAP that the licensee used and NUREG/CR-5497. In response to RAI 4 (Reference 2), the licensee stated that they used CCF parameter estimates that were based on 2003 updated events in the NRC CCF database which included CCF events subsequent to the CCF events used in NUREG/CR-5497. The licensee also stated that the WCAP CCF mapping process followed NUREG/CR-5485, "Guidelines on Modeling Common-Cause Failures in Probabilistic Risk Assessments." The staff finds the resolution of this F&O to be adequate since the CCF data used reflects the more up-to-date data sources than in NUREG/CR-5497.

Based on the licensee's assessment using the applicable PRA standard and RG 1.200, the staff concludes that the level of PRA quality, combined with the proposed evaluation and disposition of gaps, is sufficient to support the evaluation of the proposed changes to the surveillance frequencies within the SFCP, and is consistent with regulatory position 2.3.1 of RG 1.177.

3.1.4.2 Scope of the PRA The licensee is required to evaluate each proposed change to a relocated surveillance frequency using the guidance contained in NEI 04-10 to determine its potential impact on risk, from internal events, fires, seismic, other external events, and from shutdown conditions. The potential impact on risk includes both CDF and LERF metrics. In cases where a PRA of sufficient scope or when quantitative risk models were 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 negligible or zero.

In RAI 3 of letter dated June 3, 2014 (Reference 17), the NRC staff requested the licensee to describe how the fire and seismic events will be addressed in the SFCP. In response to RAI 3 (Reference 2), the licensee stated that the fire and seismic events will be assessed using a qualitative screening analysis for the STI change. If the qualitative information is not sufficient for the external events (Step 1 Oa); then a bounding analysis would be performed using the seismic and fire PRA analysis (Step 10b). Also, the licensee plans to use their peer reviewed Fire PRA model developed for the National Fire Protection Administration (NFPA) 805 to perform quantitative risk assessment sensitivity cases in accordance with NEI 04-10. The licensee also stated that NEI 04-10 guidance will also be applied for other external events hazards analyses, where a qualitative or bounding approach would be used. This also includes the shutdown risk model which uses the defense-in-depth shutdown risk assessment process using NUMARC 91-06.

The licensee's evaluation methodology is sufficient to ensure that the scope of the risk contribution from each surveillance frequency change is properly identified for evaluation, and is consistent with regulatory position 2.3.2 of RG 1.177.

3.1.4.3 PRA Modeling The licensee will determine 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 common cause failure 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 risk 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, and by sensitivity studies identified in NEI 04-

10.

The licensee will perform quantitative evaluations of the impact of selected testing strategy (i.e.,

staggered testing or sequential testing) consistent with the guidance in NUREG/CR-6141, "Handbook of Methods for Risk-Based Analyses of Technical Specifications," and NUREG/CR-5497, "Standard for Common Cause Parameter Estimation," as discussed in NEI 04-10.

Thus, through the application of NEI 04-10, the BVPS PRA 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 of RG 1.177.

3.1.4.4 Assumptions for Time Related Failure Contributions The failure probabilities of SSCs modeled in the BVPS PRA do not distinguish between the standby time-related contribution and a cyclic demand-related contribution. The licensee will assume all failures are time-related in calculating the risk impact of a proposed STI change, to obtain the maximum test-limited risk contribution. The NEI 04-10 criteria adjust the time-related failure contribution of SSCs affected by the proposed change to surveillance frequency. This is consistent with RG 1.177, Section 2.3.3, which permits separation of the failure rate contributions into demand and standby for evaluation of surveillance requirements. If the available data do not support distinguishing between the 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, and will be confirmed by the required monitoring and feedback that is implemented after the change in surveillance frequency is implemented. The process requires consideration of qualitative sources of information with regards to potential impact of test frequency on SSC performance, including industry and plant-specific operating experience, vendor recommendations, industry standards, and code-specified test intervals. Thus, the process is not reliant upon risk analyses as the sole basis for the proposed changes.

The potential benefits of reduced surveillance frequency, including reduced downtime, lesser potential for restoration errors, reduction of potential for test caused transients, and reduced test-caused wear of equipment, are identified qualitatively, but are conservatively not required to be quantitatively assessed. Thus, through the application of NEI 04-10, the licensee has employed reasonable assumptions with regard to extension of STls, and is consistent with Regulatory Position 2.3.4 of RG 1.177.

3.1.4.5 Sensitivity and Uncertainty Analyses NEI 04-10 requires sensitivity studies to 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 Capability Category II of ASME PRA Standard (ASME RA-Sb-2005) (Reference 13). 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. Required monitoring and feedback of SSC performance once the revised surveillance frequencies are implemented will also be performed. Thus, through the application of NEI 04-10, the licensee has appropriately considered the possible impact of PRA model uncertainty and sensitivity to key assumptions and model limitations, and is consistent with Regulatory Position 2.3.5 of RG 1.177.

3.1.4.6 Acceptance Guidelines The licensee will 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 the guidance contained in NRC approved NEI 04-10 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 are consistent with the risk acceptance guidelines in RG 1.17 4. When the RG 1.17 4 acceptance guidelines are not met, the process either considers revised surveillance frequencies which are consistent with RG 1.17 4, or the process terminates without permitting the proposed changes. When quantitative results are unavailable to permit comparison to risk acceptance guidelines, appropriate qualitative analyses are required to demonstrate that the associated risk impact of a proposed change to surveillance frequency is negligible or zero.

Otherwise, bounding quantitative analyses are required which demonstrate the risk impact is at least one order of magnitude lower than the RG 1.17 4 acceptance guidelines for very small changes in risk. In addition to assessing each individual SSC surveillance frequency change, the cumulative impact of all changes must result in a risk impact below 1 E-5 per year for change to CDF, and below 1 E-6 per year for change to LERF, and the total CDF and total LERF must be reasonably shown to be less than 1 E-4 per year and 1 E-5 per year, respectively. These are consistent with the risk acceptance guidelines in RG 1.17 4, as referenced by RG 1.177 for changes to surveillance frequencies. The assessment of cumulative risk is a requirement to calculate the change in risk from a baseline model utilizing failure probabilities based on the surveillance frequencies prior to implementation of the SFCP, compared to a revised model with failure probabilities based on changed surveillance frequencies. The staff further notes that FENOC includes a provision to exclude the contribution to cumulative risk from individual changes to surveillance frequencies associated with small risk increases (less than 5E-8 CDF and 5E-9 LERF) once the baseline PRA models are updated to include the effects of the revised surveillance frequencies.

The quantitative acceptance guidance of RG 1.17 4 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 SSCs. The licensee's application of NEI 04-10 provides acceptable methods for evaluating the risk increase of proposed changes to surveillance frequencies, consistent with Regulatory Position 2.4 of RG 1.177. Therefore, the proposed licensee methodology satisfies the fourth key safety principle of RG 1.177 by assuring 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 adoption of TSTF-425 requires application of NEI 04-10 in the SFCP. NEI 04-10 requires performance monitoring of SSCs whose surveillance frequency has 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 monitoring of equipment performance. In the event of degradation of SSC performance, the surveillance frequency will be reassessed in accordance with the methodology, in addition to any corrective actions which may apply as part of the maintenance rule requirements. The performance monitoring and feedback specified in NEI 04-10 is sufficient to reasonably assure acceptable SSC performance, and is consistent with regulatory position 3.2 of RG 1.177. Thus, the fifth key safety principle of RG 1.177 is satisfied.

3.2 Deviations from TSTF-425 In order for the licensee to adopt TSTF-425 for BVPS, the SR frequencies that were being moved to the SFCP cannot meet any of the four exclusion criteria located in TSTF-425 Rev. 3.

During its review of the SR frequencies that were requested to be moved to the SFCP, the NRC staff noticed that the NOTE in SR 3.3.2.6 is specific to BVPS-2 operations only, and that the frequency is related to a specific condition for the performance of the SR. Specifically, SR 3.3.2.6 requires that a slave relay test be performed every 92 days unless the NOTE is met.

The NOTE allows the slave relay test to be performed every 12 months provided a satisfactory contact leading analysis has been completed, and a satisfactory slave relay service life has been established for the slave relay being tested. This SR was originally changed by NRC SE dated May 14, 2004 (Reference 18). In the SE, the NRC staff concluded, in part, that:

[T]he NRC staff finds the proposed 12-month STI for the slave relays acceptable with the following requirements:

( 1) To ensure that the contact loading analysis for the slave relays has been performed to determine the acceptability of these relays; (2) To determine the qualified life for the continuously energized slave relays based on plant-specific environmental conditions.

The licensee's April 6, 2004, letter revised the TS 4.3.2.1.1 footnote (1) requirements to capture the above conditions. The NRC staff has determined that the revised footnote adequately captures the above conditions, and is, therefore, acceptable.

Therefore, the surveillance frequency and associated NOTE for BVPS-2 meet the exclusion criteria of "Frequencies that are related to specific conditions [ ] or conditions for the performance of a surveillance requirement [ ]," located in TSTF-425, and need to be retained in the TSs.

The NRC staff asked RAI 8, documented by memo dated January 20, 2015 (Reference 19),

which requested that the licensee either provide a justification for removing the NOTE associated with SR 3.3.2.6, or provide an updated TS page keeping the NOTE and associated time frames in the TS for BVPS-2. In Reference 4, the licensee provided a justification for removing the NOTE stating, in part, that:

The BVPS Unit 2 slave relay surveillance test interval is at 12 months because the supporting contact loading analysis that determined the solid state protection system (SSPS) slave relays contacts are adequate for the applied loads has been completed. The contact loading analysis concluded that the slave relay contacts are adequate for the application with the exception of two relays (one from each train). In 2004, a condition report (CR) was initiated to address those exceptions and the CR's corrective action has been completed, which added contacts in series to the applicable circuits to increase the effective contact rating via a design modification. A satisfactory service life has been established for the Unit 2 relays at 19 years for the energized slave relays and 40 years for the de-energized slave relays. This replacement schedule is the same for the Unit 2 Westinghouse AR440 type slave relays as well as the Potter Brumfield MOR type slave relays and is consistent with WCAP-13877 and WCAP-13878, which has been accepted by the NRC [Reference 20]. Based on the above, a satisfactory contact loading analyses has been completed for the Unit 2 slave relays.

Based on the satisfactory resolution of the conditions stated in the NRC SE (Reference 18), and the satisfactory slave relay service life, the condition imposed by the NOTE can be removed.

Therefore, the frequency associated with SR 3.3.2.6 no longer meets the exclusion criteria and can be moved to the SFCP in accordance with TSTF-425.

3.3 Addition of Surveillance Frequency Control Program to TS Section 5 The licensee has included the SFCP and specific requirements into TS Section 5.5.15, 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 these 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 Technical Specifications Initiative Sb, 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.

3.4 Summary and Conclusions The NRC staff has 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 TS Section 5.5.15, Administrative Controls. The SFCP and TS Section 5.5.15 references NEI 04-10, which provides a risk-informed methodology using plant-specific risk insights and performance data to revise surveillance frequencies within the SFCP. The NRC staff has found that this methodology is acceptable for referencing in the TS to the extent specified and under the limitation delineated in NEI 04-10, and supports relocating surveillance frequencies from TS to a licensee-controlled document,.

The proposed licensee adoption of TSTF-425 and risk-informed methodology of NEI 04-10, as referenced in TS Section 5.5.15, satisfies the key principles of risk-informed decision making applied to changes to TS as delineated in RG 1.177 and RG 1.17 4, in that:

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

The regulations in 10 CFR 50.36(c)(3) state, 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 and administratively controlled in accordance with the TS SFCP, the licensee continues to meet the regulatory requirements of 10 CFR 50.36, and specifically, 10 CFR 50.36(c)(3), surveillance requirements for BVPS.

The NRC has concluded, on the basis of the considerations discussed above, that the proposed change is acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Pennsylvania State official was notified of the proposed issuance of the amendments. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 and change surveillance requirements. The NRC staff has determined that the amendments involve no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (79 FR 3416). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b),

no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

6.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

7.0 REFERENCES

1. Larson, E.A., to U.S. NRC, "License Amendment Request for Adoption of TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee-Control Risk Informed Technical Specification Task Force (RITSTF) Initiative Sb, October 18, 2013. (ADAMS Accession No. ML13295A006)

2. Larson, E.A., to U.S. NRC, "Response to Request for Additional Information Regarding License Amendment to Adopt Technical Specification Task Force Traveler 425 (TAC Nos.

MF2942 and MF2943)," June 26, 2014. (ADAMS Accession No. ML14177A514).

3. Larson, E.A., to U.S. NRC, "Response to Request for Additional Information Regarding License Amendment to Adopt Technical Specification Task Force Traveler 425 (TAC Nos.

MF2942 and MF2943)," September 21, 2014. (ADAMS Accession No. ML14265A158).

4. Larson, E.A. to U.S. NRC, "Response to Request for Additional Information Regarding License Amendment to Adopt Technical Specification Task Force Traveler 425 (TAC Nos.

MF2942 and MF2943)," February 4, 2015. (ADAMS Accession No. ML15035A282).

5. TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control-RITSTF Initiative 5b," March 18, 2009. (ADAMS Accession No. ML090850642).

6. NEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 58, Risk-Informed Method for Control of Surveillance Frequencies," April 2007. (ADAMS Accession No. ML071360456).

7. Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 04-10, Revision 1, "Risk-Informed Technical Specification Initiative 5b, "Risk-Informed Method for Control of Surveillance Frequencies." September 19, 2007 (ADAMS Accession No. ML072570267).

8. Final Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors. (Published on July 22, 1993, 58 FR 39132).

9. Use of Probabilistic Risk Assessment Methods in Nuclear Regulatory Activities; Final Policy Statement (Published on August 16, 1995, 60 FR 42622).

10. Regulatory Guide 1.17 4, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," NRC, Revision 1, November 2002 (ADAMS Accession No. ML023240437).

11. Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications," August 1998. (ADAMS Accession No. ML003740176).

12. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 1, January 2007. (ADAMS Accession No. ML070240001).

13. ASME PRA Standard ASME RA-Sb-2005, "Addenda to ASME RA-S-2002, "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Application." December 30, 2005

14. NEI 00-02, Revision 1 "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance," Revision 1, May 2006. (ADAMS Accession No. ML061510621).

15. NEI 05-04, "Process for Performing Follow-On PRA Peer Reviews Using the ASME PRA Standard," Revision 0, August 2006.

16. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2, March 2009 (ADAMS Accession No. ML090410014)

17. U.S. NRC to E.A. Larson, "Beaver Valley Power Station, Units 1 and 2 - Request for Additional Information RE: License Amendment Request to Adopt Technical Specifications Task Force Traveler 425 (TAC Nos. MF2942 and MF2943)." June 3, 2014. (ADAMS Accession No. ML14133A069)

18. U.S. NRC to L.W. Pearce, "Beaver Valley Power Station, Unit No. 2 - Issuance of Amendment Re: Engineered Safeguards Features Actuation System (ESFAS) Slave Relay Surveillance Test Interval Extension (TAC No. MB7589)." May 14, 2004. (ADAMS Accession No. ML041030082).

19. Whited, J.A. to Khanna, M.K., "Beaver Valley Power Station, Units 1 and 2 - DRAFT Request for Additional Information (TAC Nos. MF2942 and MF2943)." January 20, 2015.

(ADAMS Accession No. ML15016A439).

20. U.S. NRC to H.A. Sepp, "Review of Westinghouse Topical Reports WCAP-13877, Revision 2-P and WCAP-13878-P, Revision 2 on Solid State Protection System (SSPS) Slave Relays (TAC No. MA7264)." July 12, 2000. (ADAMS Accession No. ML003731486).

Principal Contributors:

Jonathan Evans Gursharan Singh Date: March 6, 2015

ML14322A461

via memo dated OFFICE LPL 1-2/PM LPL 1-2/LA APLA/BC*

STSB/BC El CB/BC OGC (NLO)

LPL 1-2BC LPL 1-2/PM NAME JWhited ABaxter HHamzehee RElliot JThorp A Ghosh DBroaddus JWhited

changes only (DLRahn for)

DATE 02/05/2015 12/08/2014 11/10/2014 02/12/2015 02/12/2015 02/27/2015 03/04/2015 03/06/2015

02/10/15

v t e Letter Sequence Approval
TAC:MF2942, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5B (Approved, Closed) TAC:MF2943, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5B (Approved, Closed)
Initiation Request Acceptance Administration Questions 13 May 2014 20 August 2014 20 August 2014 20 January 2015 3 June 2014 28 August 2014 Answers 26 June 2014 21 September 2014 4 February 2015 Results Approval Other:
MONTHYEAR2014-08-20 [Table View]

ML14322A461

Text

SUBJECT:

Dear Mr. Larson:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

7.0 REFERENCES

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