Text

Issuance of License Amendments Auxiliary Feedwater System Modification
	ML110230016
Person / Time
Site:	Point Beach
Issue date:	03/25/2011
From:	Beltz T; Plant Licensing Branch III
To:	Meyer L; Point Beach
	beltz T, NRR/DORL/LPL3-1, 301-415-3049
References
	TAC ME1081, TAC ME1082
	Download: ML110230016 (74)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 March 25, 2011 Mr. Larry Meyer Site Vice President NextEra Energy Point Beach, LLC Point Beach Nuclear Plant 6610 Nuclear Road Two Rivers, WI 54241-9516

SUBJECT:

POINT BEACH NUCLEAR PLANT (PBNP), UNITS 1 AND 2 - ISSUANCE OF LICENSE AMENDMENTS RE: AUXILIARY FEEDWATER SYSTEM MODIFICATION (TAC NOS. ME1081 AND ME1082)

Dear Mr. Meyer:

The Nuclear Regulatory Commission has issued the enclosed Amendment Nos. 238 and 242 to Renewed Facility Operating License Nos. DPR-24 and DPR-27, for PBNP, Units 1 and 2. The amendment provides changes to the auxiliary feedwater (AFW) system design and the Technical Specifications in response to your application dated April 7, 2009, as supplemented by letters dated June 17 (two letters), September 11, September 25, October 9, November 20 (two letters), November 21 (two letters), November 30, December 8, and December 16 of 2009; and January 7, January 8, January 22, February 11, February 25, March 3, April 15, April 22, April 28, July 8, July 28, August 2, August 9, August 24, October 15, November 1, November 12 (two letters), November 30, and December 21 of 2010. The proposed changes were originally included as part of the April 7, 2009, extended power uprate (EPU) license amendment request, but subsequently divided into a separate licensing action for independent technical review.

The amendment changes the AFW system design and Technical Specifications (TS) 3.7.5, "Auxiliary Feedwater (AFW)," and TS 3.7.6, "Condensate Storage Tank (CST)," resulting from 1) modifications to the AFW system to support requirements for transients and other accidents at EPU conditions; 2) automatic AFW switchover from a CST suction source to a safety-related Service Water source; and 3) instrumentation setpoint changes supporting the aforementioned physical modifications. The upgrades and modifications to the AFW system are being installed to provide additional capacity and reliability for the system. Although the proposed changes are also designed to support the requirements for transients and other accidents at EPU conditions, the changes for this amendment have been evaluated using the current licensing basis.

L. Meyer

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

Sincerely, ~

~rry A. Beltz, Senior Project Manager Plant Licensing Branch 111-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-266 and 50-301

Enclosures:

1. Amendment No. 238 to DPR-24

2. Amendment No. 242 to DPR-27

3. Safety Evaluation cc w/encls: Distribution via Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 NEXTERA ENERGY POINT BEACH, LLC DOCKET NO. 50-266 POINT BEACH NUCLEAR PLANT, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 238 Renewed License No. DPR-24

1.

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

A.

The application for amendment by NextEra Energy Point Beach, LLC (the licensee), dated April 7,2009, as supplemented by letters dated June 17 (two letters), September 11, September 25, October 9, November 20 (two letters).

November 21 (two letters), November 30, December 8, and December 16 of 2009; and January 7, January 8, January 22, February 11, February 25, March 3, April 15, April 22, April 28, July 8, July 28, August 2, August 9, August 24, October 15, November 1, November 12 (two letters), November 30, and December 21 of 2010, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this license 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

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 4.8 of Renewed Facility Operating License No. DPR-24 is hereby amended to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 238, are hereby incorporated in the renewed operating license.

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

3.

Accordingly, the license is amended by two new license conditions to be added to Appendix C, Additional Conditions, with wording as follows:

I.

NextEra Energy Point Beach, LLC shall modify the motor driven auxiliary feedwater and the turbine driven auxiliary feedwater pump systems to ensure they are powered from independent DC power source.

II. NextEra Energy Point Beach, LLC shall implement modifications to reduce emergency diesel generator (EDG) loading such that the maximum loading will not exceed the 2000-hour rating of the EDGs.

These license conditions shall be implemented prior to the end of the Unit 2 refueling outage in the spring of 2011.

4.

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

FOR THE NUCLEAR REGULATORY COMMISSION Robert J. Pascarelli, Chief Plant Licensing Branch 111-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License No. DPR-24, Appendix C, and Technical Specifications Date of Issuance: March 25, 2011

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 NEXTERA ENERGY POINT BEACH, LLC DOCKET NO. 50-301 POINT BEACH NUCLEAR PLANT, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 242 Renewed License No. DPR-27

1.

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

A.

The application for amendment by NextEra Energy Point Beach, LLC (the licensee), dated April 7, 2009, as supplemented by letters dated June 17 (two letters), September 11, September 25, October 9, November 20 (two letters),

November 21 (two letters), November 30, December 8, and December 16 of 2009; and January 7, January 8, January 22, February 11, February 25, March 3, April 15, April 22, April 28, July 8, July 28, August 2, August 9, August 24, October 15, November 1, November 12 (two letters), November 30, and December 21 of 2010, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this license 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

2.

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

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 242, are hereby incorporated in the renewed operating license.

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

3.

Accordingly, the license is amended by two new license conditions to be added to Appendix C, Additional Conditions, with wording as follows:

I.

NextEra Energy Point Beach, LLC shall modify the motor driven auxiliary feedwater and the turbine driven auxiliary feedwater pump systems to ensure they are powered from independent DC power source.

II. NextEra Energy Point Beach, LLC shall implement modifications to reduce emergency diesel generator (EDG) loading such that the maximum loading wilt not exceed the 2000-hour rating of the EDGs.

These license conditions shall be implemented prior to the end of the Unit 2 refueling outage in the spring of 2011.

4.

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

FOR THE NUCLEAR REGULATORY COMMISSION J1~

Robert J. Pascarelli, Chief Plant Licensing Branch 111-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License No. DPR-27, Appendix C, and Technical Specifications Date of Issuance: March 25, 2011

ATTACHMENT TO LICENSE AMENDMENT NO. 238 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-24 AND LICENSE AMENDMENT NO. 242 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-27 DOCKET NOS. 50-266 AND 50-301 Replace the following pages of the Renewed Facility Operating License Nos. DPR-24 and DPR-27, Appendix C, and Appendix A Technical Specifications with the attached revised pages.

The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Operating License REMOVE INSERT Unit 1 License Pages 3 and 6 Unit 1 License Pages 3 and 6 Unit 2 License Pages 3 and 6 Unit 2 License Pages 3 and 6 Appendix C Unit 1 Page C-2 Unit 1 Page C-2 Unit 2 Page C-2 Unit 2 Page C-2 Technical Specifications REMOVE INSERT 3.3.2-4 3.3.2-4 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 3.3.4-3 3.3.4-3 3.7.5-1 3.7.5-1 3.7.5-2 3.7.5-2 3.7.5-3 3.7.5-3 3.7.5-4 3.7.5-4 3.7.5-5 3.7.5-5 3.7.6-1 3.7.6-1 3.8.1-8 3.8.1-8

-3 D. Pursuant to the Act and 10 CFR Parts 30,40 and 70, NextEra Energy Point Beach to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and E. Pursuant to the Act and 10 CFR Parts 30 and 70, NextEra Energy Point Beach to possess such byproduct and special nuclear materials as may be produced by the operation of the facility, but not to separate such materials retained within the fuel cladding.

4.

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

A. Maximum Power Levels NextEra Energy Point Beach is authorized to operate the facility at reactor core power levels not in excess of 1540 megawatts thermal.

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 238, are hereby incorporated in the renewed operating license.

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

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

Renewed License No. DPR-24 Amendment No. 238

-6

2. Operations to mitigate fuel damage considering the following:

a.

Protection and use of personnel assets

b.

Communications

c.

Minimizing fire spread

d.

Procedures for implementing integrated fire response strategy

e.

Identification of readily-available pre-staged equipment

f.

Training on integrated fire response strategy

g.

Spent fuel pool mitigation measures

3. Actions to minimize release to include consideration of:

a.

Water spray scrubbing

b.

Dose to onsite responders M. Additional Conditions The additional conditions contained in Appendix C, as revised through Amendment No. 238, are hereby incorporated into this license. NextEra Energy Point Beach shall operate the facility in accordance with the additional conditions.

5.

The issuance of this renewed operating license is without prejudice to subsequent licensing action which may be taken by the Commission with regard to the ongoing rulemaking hearing on the Interim Acceptance Criteria for Emergency Core Cooling Systems (Docket No. RM 50-1).

6.

This renewed operating license is effective as of the date of issuance, and shall expire at midnight on October 5, 2030.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By R. W. Borchardt, Deputy Director Office of Nuclear Reactor Regulation Attachments:

1. Appendix A - Technical Specifications

2. Appendix B - Environmental Technical Specifications

3. Appendix C - Additional Conditions Date of Issuance: December 22,2005 Renewed License No. DPR-24 Amendment No. 238

APPENDIX C ADDITIONAL CONDITIONS OPERATING LICENSE DPR-24 NextEra Energy Point Beach, LLC shall comply with the following conditions and the schedules noted below:

Amendment Number Additional Conditions Implementation Date 228 At the time of the closing of the transfer of the licenses from Wisconsin Electric Power Company (WEPCO) to FPLE Point Beach', WEPCO shall transfer to FPLE Point Beach' WEPCO's decommissioning funds in an aggregate minimum value of $200.8 million for Point Beach Unit 1. FPLE Point Beach' Immediately shall deposit such funds in an external decommissioning trust fund established by FPLE Point Beach' for Point Beach Units 1 and 2. The trust agreement shall be in a form acceptable to the NRC.

NextEra Energy Point Beach shall take no actions to cause FPL Group Capital, or its successors and assigns, to void, cancel, or modify its $70 million Support Agreement (Agreement) to NextEra Energy Point Beach, as presented in its application dated January 26.2007, or cause it to fail to perform or impair its performance under the Agreement, without the prior written consent from the NRC. The Agreement may not be amended or modified without 30 days prior written notice to the Director of Nuclear Reactor Regulation or his designee. An executed copy of the Agreement shall be submitted to the NRC no later than 30 days after the completion of the license transfers. Also, NextEra Energy Point Beach shall inform the NRC in writing anytime it draws upon the $70 million Agreement.

Immediately 238 NextEra Energy Point Beach, LLC shall modify the motor driven auxiliary feedwater and turbine driven auxiliary feedwater pump systems to ensure they are powered from independent DC power sources.

Prior to End of Spring 2011 Unit 2 Refueling Outage 238 NextEra Energy Point Beach, LLC shall implement modifications to reduce emergency diesel generator (EDG) loading such that the maximum loading will not exceed the 2000-hour rating of the EDGs.

Prior to End of Spring 2011 Unit 2 Refueling Outage

On April 16, 2009, the name "FPLE Point Beach, LLC" was changed to "NextEra Energy Point Beach, LLC."

Point Beach Unit 1 C-2 Amendment No. 238

-3 C. Pursuant to the Act and 10 CFR Parts 30, 40 and 70, NextEra Energy Point Beach to receive, possess and use at any time any byproduct source, and special nuclear material as sealed neutron sources for reactor startup, sealed source for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; D. Pursuant to the Act and 10 CFR Parts 3D, 40 and 70, NextEra Energy Point Beach to receive, possess and use in amounts as required any byproduct, source of special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and E. Pursuant to the Act and 10 CFR Parts 30 and 70, NextEra Energy Point Beach to possess such byproduct and special nuclear materials as may be produced by the operation of the facility, but not to separate such materials retained within the fuel cladding.

4.

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

A. Maximum Power Levels NextEra Energy Point Beach is authorized to operate the facility at reactor core power levels not in excess of 1540 megawatts thermal.

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 242, are hereby incorporated in the renewed operating license.

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

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

Renewed License 1\\10. DPR-27 Amendment No. 242

-6

e.

Identification of readily-available pre-staged equipment

f.

Training on integrated fire response strategy

g.

Spent fuel pool mitjgation measures

3. Actions to minimize release to include consideration of:

a.

Water spray scrubbing

b.

Dose to onsite responders L. Additional Conditions The additional conditions contained in Appendix C, as revised through Amendment No. 242, are hereby incorporated into this license. NextEra Energy Point Beach shall operate the facility in accordance with the additional conditions.

5.

The issuance of this renewed operating license is without prejudice to subsequent licensing action which may be taken by the Commission with regard to the ongoing rulemaking hearing on the Interim Acceptance Criteria for Emergency Core Cooling Systems (Docket No. RM 50-1).

6.

This renewed operating license is effective as of the date of issuance, and shall expire at midnight on March 8, 2033.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By R. W. Borchardt, Deputy Director Office of Nuclear Reactor Regulation Attachments:

1. Appendix A -Technical Specifications

2. Appendix B - Environmental Technical Specifications

3. Appendix C - Additional Conditions Date of Issuance: December 22, 2005 Renewed License No. DPR-27 Amendment No. 242

APPENDIXC ADDITIONAL CONDITIONS OPERATING LICENSE DPR-27 NextEra Energy Point Beach, LLC shall comply with the following conditions and the schedules noted below:

Amendment Number Additional Conditions 233 At the time of the closing of the transfer of the licenses from Wisconsin Electric Power Company (WEPCO) to FPLE Point Beach", WEPCO shall transfer to FPLE Point Beach* WEPCO's decommissioning funds in an aggregate minimum value of $189.2 million for Point Beach Unit 2. FPLE Point Beach" shall deposit such funds In an external decommissioning trust fund established by FPLE Point Beach" for Point Beach Units 1 and 2. The trust agreement shall be in a form acceptable to the NRC.

NextEra Energy Point Beach shall take no actions to cause FPL Group Capital, or its successors and assigns, to void, cancel, or modify its $70 million Support Agreement (Agreement) to NextEra Energy Point Beach, as presented in its application dated January 26,2007, or cause it to fall to perform or Impair its performance under the Agreement. without the prior written consent from the NRC. The Agreement may not be amended or modified without 30 days prior written notice to the Director of Nuclear Reactor Regulation or his designee. An executed copy of the Agreement shall be submitted to the NRC no later than 30 days after the completion of the license transfers. Also, NextEra Energy Point Beach shall inform the NRC in writing anytime it draws upon the $70 million Agreement.

242 j\\JextEra Energy Point Beach, LLC shall modify the motor driven auxiliary feedwater and turbine driven auxiliary feedwater pump systems to ensure they are powered from independent DC power sources.

242 NextEra Energy Point Beach, LLC shall implement modifications to reduce emergency diesel generator (EDG) loading such that the maximum loading will not exceed the 2000-hour rating of the EDGs.

Implementation Date Immediately Immediately Prior to End of Spring 2011 Unit 2 Refueling Outage Prior to End of Spring 2011 Unit 2 Refueling Outage

On April 16, 2009, the name "FPLE Point Beach, LLC" was changed to "NextEra Energy Point Beach, LLC."

Point Beach Unit 2 C-2 Amendment No. 242

3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

N 0 T E ----------------

Separate Condition entry is allowed for each AFW pump.

J.

One channel inoperable.

J.1 OR J.2 Restore channel to OPERABLE status.

Declare associated AFW pump inoperable.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Point Beach 3.3.2-4 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

3.3.2 ESFAS Instrumentation SURVEILLANCE REQUIREMENTS

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

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

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.2.2

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

The continuity check may be excluded.

Perform ACTUATI()N L()GIC TEST.

31 days on a STAGGE:RE:D TE:ST BASIS SR 3.3.2.3 Perform C()T.

92 days SR 3.3.2.4 Perform MASTE:R RE:LAY TE:ST.

18 months SR 3.3.2.5 Perform SLAVE: RE:LAY TE:ST.

18 months SR 3.3.2.6 Perform TAD()T.

31 days SR 3.3.2.7 Perform TAD()T.

18 months SR 3.3.2.8

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

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

Perform CHANNE:L CALIBRATI()N.

18 months Point Beach 3.3.2-5 Unit 1 - Amendment No. 201 Unit 2 - Amendment No. 206

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

Engineered Safety Feature Actuation System Instrumentation APPLICABLE REQUIRED SURVEIUJ.\\NCE ALLOWABLE FUNCTION MODES Q1ANNaS CONDITIONS REQUIREMENTS VALUE

1.

Safety Injection

a.

Manual Initiation 1,2,3,4 2

B SR 3.3.2.7 NA

b.

Automatic Actuation Logic and Actuation Relays 1,2,3,4 2 traIns C

SR SR SR 3.3.2.2 3.3.2.4 3.3.2.5 NA

c.

Containment Pressure-High 1,2,3 3

D SR SR SR 3.3.2.1 3.3.2.3 3.3.2.8

$ 6 psig

d.

Pressurizer Pressure-Low 1,2,3(a) 3 0

SR SR SR 3.3.2.1 3.3.2.3 3.3.2.8

~ 1715 psig

e.

Steam Line Pressure-Low 1,2,3(b) 3 per steam line D

SR SR SR 3.3.2.1 3.3.2.3 3.3.2.8

~ 500(c) pslg

2.

Containment Spray

a.

Manual Initiation 1,2,3,4 2

E SR 3.3.2.7 NA

b.

Automatic Actuation Logic and Actuation Relays 1,2.3,4 2 trains C

SR SR SR 3.3.2.2 3.3.2.4 3.3.2.5 Nil.

c.

Containment Pressure-High High 1,2.3 2 sets of 3 0

SR SR SR 3.3.2.1 3.3.2.3 3.3.2.8

$ 30 pslg (continued)

(a)

(b)

(c)

Pressurizer Pressure> 1600 psig.

Pressurizer Pressure> 1600 psig. except during Reactor Coolant System hydrostatic testing.

Time constants used in the leadllag controller are t1 <: 12 seconds and 12 ~ 2 seconds.

Point Beach 3.3.2-6 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

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

Engineered Safety Feature Actuation System Instrumentation APPLICABLE REQUIRED SURVElUPNCE ALLOWABLE FUNCTION MODES CHt>.NNELS CONDITIONS REQUIREMENTS VALUE

3.

Containment Isolation

a.

Manual Initiation 1,2,3,4 2

B SR 3.3.2.7 NA

b. Automatic Actuation 1,2,3,4 2 trains C

SR 3.3.2.4 NA Logic and Actuation SR 3.3.2.5 Relays

c.

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

4.

Steam Line Isolation

a.

Manual Initiation 1,2(d),3(d) 11100p F

SR 3.3.2.7 NA

b.

Automatic Actuation 1,2(d),3(d) 2 trains G

SR 3.3.2.2 NA Logic and Actuation SR 3.3.2.5 Relays

c.

Containment 3

D SR 3.3.2.1 s 20 pslg 1,2(d),3(d)

Pressure-High High SR 3.3.2.3 SR 3.3.2.8

d.

High Steam Flow 2 per D

SR 3.3.2.1 s a.p 1.2(d),3(d) steam SR 3.3.2.3 corresponding to line SR 3.3.2.8 0.66 x 10 6 Ib/hr at 1005 psig COincident with Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Injection and Coincident with 3

D SR 3.3.2.1 Tavg-LOw SR 3.3.2.3 SR 3.3.2.8

e.

High High Steam Flow 2 per D

SR 3.3.2.1 s; a.p steam SR 3.3.2.3 corresponding to line SR 3.3.2.8 4 x 106 Ib/hr at 806 pslg Coincident with Safety Refer to FUnction 1 (Safety Injection) for all initiation functions and requirements.

Injection (continued)

(d)

Except when all MSIVs are closed and de-actlvated.

Point Beach 3.3.2-7 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

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

Engineered Safety Feature Actuation System Instrumentation APPLICABLE REQUIRED SURVEILlANCE ALLOWABLE FUNCTION MODES CHANNELS CONDITIONS REQUIREMENTS VALUE

5.

Feedwater Isolation

a.

Automatic Actuation Logic and Actuation Relays 1,2(e),3(e) 2 trains G

SR SR SR 3.3.2.2 3.3.2.4 3.3.2.5 NA

b.

SG Water Level-High 1,2(e),3(e) 3 per SG D

SR SR SR 3.3.2.1 3.3.2.3 3.3.2.8 NA

c.

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

6.

Auxiliary Feedwater

a.

Automatic Actuation Logic and Actuation Relays 1,2,3 2 trains G

SR 3.3.2.2 NA

b.

SG Water Level-Low Low 1,2,3 3 per SG D

SR SR SR 3.3.2.1 3.3.2.3 3.3.2.8

~ 20%

c.

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

d.

Undervoltage Bus A01 and A02 1,2 2 per bus H

SR SR 3.3.2.6 3.3.2.8

~ 3120 V e

AFW Pump Suction Transfer on Suction Pressure - Low 1,2,3 1 per pump J

SR SR SR 3.3.2.1 3.3.2.3(1) 3.3.2.8(1)

~ 5.8 psig

7.

Condensate Isolation

a.

Containment Pressure-High 1,2(e),3(e) 3 D

SR SR SR 3.3.2.1 3.3.2.3 3.3.2.8

5 6 psig

b.

Automatic Actuation Logic and Actuation Relays 1,2(e),3(e) 2 trains G

SR SR SR 3.3.2.2 3.3.2.4 3.3.2.5 N/A

8.

SI Block-Pressurizer Pressure 1,2,3 3

SR SR SR 3.3.2.1 3.3.2.3 3.3.2.8

5 1800 psig (e)

Except when all MFRVs and associated bypass valves are closed and de-activated.

(f)

Table 3.3.2-1 Notes 1 and 2 are applicable.

Point Beach 3.3.2-8 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

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

Engineered Safety Feature Actuation System Instrumentation Note 1:

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

Note 2:

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

Point Beach 3.3.2-9 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

3.3.4 LOP DG Start Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3.3.4.3 Perform CHANNEL CALIBRATION with Allowable Value as follows:

a.

4.16 kV loss of voltage Allowable Value

~ 3156 V with a time delay of ~ 1.8 seconds and.5. 2.3 seconds (Bus Loss of Voltage Relay) and 2:. 1.95 seconds and.5.

3.55 seconds (EDG Breaker Close Delay Relay).

b.

4.16 kV degraded voltage Allowable Value

2: 3937 V with a time delay of

< 5.68 seconds (Bus Degraded Voltage Relay) and < 39.14 seconds (Bus Time Delay Relay).

c.

480 V loss of voltage Allowable Value 256 V

+/- 3% with a time delay of?:. 1.15 seconds and.5. 1.6 seconds.

FREQUENCY 18 months Point Beach 3.3.4-3 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

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

LC03.7.5 The AFW System shall be OPERABLE with; one turbine driven AFW pump system and one motor driven AFW pump system:

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

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

APPLICABILITY:

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

ACTIONS

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

LCO 3.0.4.b is not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A.

Turbine driven AFW pump system inoperable due to one inoperable steam supply.

OR

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

Only applicable if MODE 2 has not been entered following refueling.

A.1 Restore affected equipment to OPERABLE status.

7 days 10 days from discovery of failure to meet the LCO Turbine driven AFW pump system inoperable in MODE 3 following refueling.

(continued)

Point Beach 3.7.5-1 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

AFW System 3.7.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B.

One AFW pump system inoperable in MODE 1, 2 or 3 for reasons other than Condition A.

B.1 Restore AFW pump system to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months AND 10 days from discovery of failure to meet the LCO C.

Turbine driven AFW pump system inoperable due to one inoperable steam supply.

AND Motor driven AFW pump system inoperable.

C.1 OR C.2 Restore the steam supply to the turbine driven pump system to OPERABLE status.

Restore the motor driven AFW pump system to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months if motor driven AFW pump system is available from the opposite unit.

(continued)

Point Beach 3.7.5-2 Unit 1 - Amendment No. 238.

Unit 2 - Amendment No. 242

3.7.5 AFW System ACTIONS (continued)

D.

CONDITION Required Action and associated Completion Time of Condition A, B, or C not met.

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

Be in MODE 4.

COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 18 hours E.

Two AFW pump systems inoperable in MODE 1, 2, or 3.

E.1

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

LCO 3.0.3 and all other LCO Required Actions requiring MODE changes are suspended until one AFW pump system is restored to OPERABLE status.

Initiate action to restore one AFW pump system to OPERABLE status.

Immediately F.

Motor driven AFW pump system inoperable in MODE 4.

F.1 Initiate action to restore motor driven AFW pump system to OPERABLE status.

Immediately Point Beach 3.7.5-3 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

3.7.5 AFW System SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1

~~------~------------------NOTE--------------------------

AFW pump system(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.

31 days SR 3.7.5.2

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 THERMAL POWER exceeds 2% RTP.

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

In accordance with the Inservice Testing Program SR 3.7.5.3

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

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

18 months Point Beach 3.7.5-4 Unit 1 - Amendment No. 201 Unit 2 - Amendment No. 206

3.7.5 AFW System SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.5.4 SR 3.7.5.5

N()TES-----------------------.

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

?: 1000 psig in the steam generator.

2.

AFW pump system(s} may be considered

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

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

Verify proper alignment of the required AFW flow paths by verifying flow from the condensate storage tank to each steam generator supplied by the respective AFW pump system.

18 months Prior to THERMAL P()WER exceeding 2%

RTP whenever unit has been in M()DE 5, M()DE 6, or defueled for a cumulative period of

> 30 days Point Beach 3.7.5-5 Unit 1 - Amendment No. 201 Unit 2 - Amendment No. 206

CST 3.7.6 3.7 PLANT SYSTEMS 3.7.6 Condensate Storage Tank (CST)

LCO 3.7.6 The CST shall be OPERABLE.

APPLICABILITY:

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

CST inoperable.

A.1 Restore CST to OPERABLE status.

7 days B.

Required Action and associated Completion Time not met.

B.1 AND B.2 Be in MODE 3.

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

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 18 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.6.1.A OR SR 3.7.6.1.B OR SR 3.7.6.1.C Verify the CST level is ;::: 21,150 gallons.

(2 CSTs either cross-tied or individually aligned)

Verify the CST level is;::: 35,837 gallons.

(1 CST supplying two units)

Verify the CST level is;::: 14,100 gallons.

(2 CSTs supplying one unit)

FREQUENCY 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Point Beach 3.7.6-1 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

3.8.1 AC Sources-Operating SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.6 SR 3.8.1.7 SURVEILLANCE Verify each standby emergency power source:

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.

Returns to ready-to-Ioad operation.

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

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

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

3. If performed with the standby emergency power source synchronized with offsite power, it shall be performed at a power factor,:::, 0.87.

However, if grid conditions do not permit, the power factor limit is not required to be met.

Under this condition, the power factor shall be maintained as close to the limit as practicable.

FREQUENCY 18 months Verify each standby emergency power source operates for 2:. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at 2:. 2850 kW (G01/G02),

2:. 2848 kW (G03/04).

18 months Point Beach 3.8.1-8 Unit 1 - Amendment No. 238 Unit 2 - Amendment No. 242

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 238 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-24 AND AMENDMENT NO. 242 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-27 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 DOCKET NOS. 50-266 AND 50-301

1.0 INTRODUCTION

By letter to the U.S. Nuclear Regulatory Commission (NRC) dated April 7, 2009 1

, as supplemented by additional letters2, NextEra Energy Point Beach, LLC (formerly FPL Energy Point Beach, LLC) (NextEra, the licensee) requested a license amendment to change the auxiliary feedwater (AFW) system design and associated Technical Specifications (TS) 3.7.5, "Auxiliary Feedwater (AFW)," and TS 3.7.6, "Condensate Storage Tank (CST)," at Point Beach Nuclear Plant (PBI\\IP), Units 1 and 2.

The supplemental letters provided additional information that clarified the application, 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 on September 21,2010, (75 FR 57525).

1 Agencywide Documents Access and Management System (ADAMS) Accession Number (AN) ML091250564 2 June 17, 2009 (2 letters - AN ML091690090 and AN ML091690087); September 11, 2009 (AN ML092570205);

September 25, 2009 (AN ML092750395); October 9, 2009 (AN ML092860098); November 20, 2009 (2 letters AN ML093270030 and AN ML093270079); November 21,2009 (2 letters - AN ML093270032 and AN ML093270035); November 30,2009 (AN ML093360143); December 8,2009 (AN ML093430114); December 16, 2009 (AN ML093510809); January 7, 2010 (AN ML100080013); January 8, 2010 (AN ML100110037); January 22, 2010 (AN ML100250011); February 11,2010 (AN ML100470786); February 25,2010 (AN ML100600576); March 3, 2010 (AN ML100630133); April 15, 2010 (AN ML101050357); April 22, 2010 (AN ML101130030); April 28, 2010 (AN ML101190081); July 8, 2010 (AN ML101890785); July 28, 2010 (AN ML102110116); August 2, 2010 (AN ML102180370); August 9,2010 (AN ML102220146); August 24,2010 (AN ML102370338); October 15, 2010 (AN ML102910394); November 1, 2010 (AN ML103060227); November 12,2010 (2 letters -AN ML103160341 and AN ML103160385); November 30,2010 (AN ML103340421); and December 21,2010 (AN ML103550593).

2.0

- 2 The PBNP AFW system is being redesigned, in part, to support implementation of the future extended power uprate (EPU). The EPU license amendment request (LAR) was submitted by the licensee in the April 7, 2009, letter. In a letter dated April 22, 2010, (Agencywide Documents Access and Management System (ADAMS) Accession No. ML101130030), the licensee requested implementation of the AFW modifications at the current licensed power levels under the current licensing basis (CLB) methods. Two new higher capacity motor-driven AFW (MDAFW) pumps will be installed to meet the higher EPU flow requirements. The AFW system's function is to supply high-pressure feedwater to the steam generators (SG) in order to maintain a water inventory for removal of heat energy from the reactor coolant system by secondary side steam release, in the event of inoperability or unavailability of the main feedwater (MFW) system.

The licensee's application requests NRC approval of changes to the AFW system and TSs resulting from 1) modifications to the AFW system to support requirements for transients and other accidents at EPU conditions; 2) automatic AFW switchover from a CST suction source to a safety-related service water (SW) source; and 3) instrumentation setpoint changes supporting the aforementioned physical modifications. The upgrades and modifications to the AFW system are being installed to provide additional capacity and reliability for the system.

REGULATORY EVALUATION The design basis for the AFW system is to supply high-pressure feedwater to the steam generators in order to maintain a water inventory for removal of heat energy from the reactor coolant system by secondary side steam release in the event of inoperability or unavailability of the MFW system.

The NRC acceptance criteria for the AFW system are based on the general design criteria (GDC) specified in Title 10 of the Code of Federal Regulations (10 CFR) Part 50 Appendix A.

However, the licensee's Final Safety Analysis Report (FSAR) Section 1.3, states that the GDC used during the licensing of PBNP predates those provided today in 10 CFR 50, Appendix A.

Since the GDC used during the initial licensing of PBNP predates those provided in 10 CFR 50, Appendix A, the staff used the CLB as stated in the FSAR, which provides a functional description of how PBNP will meet the Atomic Energy Commission proposed GDC. In the discussion below, the parenthetical numbers indicate the numbers of the Atomic Industrial Forum version of the proposed General Design Criterion (PBNP GDC).

GDC 1, insofar as it requires that structures, systems and components (SSCs) important to safety be designed, fabricated, erected, constructed, tested, and inspected to quality standards commensurate with the importance of the safety functions to be performed.

(PBNP GDC 1): Those systems and components of reactor facilities which are essential to the prevention or the mitigation of the consequences of nuclear accidents which could cause undue risk to the health and safety of the public shall be identified and then designed, fabricated, and erected to quality standards that reflect the importance of the safety function to be performed.

GDC 2, insofar as it requires that structures housing the system and the system itself being capable of withstanding the effects of earthquakes, tornados, and floods.

(PBNP GDC 2): Those systems and components of reactor facilities which are essential to the prevention or to the mitigation of the consequences of nuclear accidents shall be

- 3 designed, fabricated, and erected to performance standards that enable such systems and components to withstand the forces that might reasonably be imposed by the occurrence of an extraordinary natural phenomenon such as earthquake, tornado, flooding condition, high wind, or heavy ice. As a Class I system, AFW components are designed such that there is no loss of function in the event of a maximum hypothetical earthquake.

GOC 4, insofar as it requires that safety-related structures, systems, and components important to safety be appropriately protected against dynamic effects, including the effects of missiles, pipe whipping, and discharging fluids that may result from equipment failures.

(PBNP GOC 40): Adequate protection for those engineered safety features shall be provided against dynamic effects and missiles that might result from plant equipment failures. Ensure that safety-related SSCs are adequately protected with respect to pipe ruptures and the associated dynamic effects as addressed in the PBNP FSAR, Appendix A.2, "High Energy Pipe Failure Outside Containment."

GOC 5, insofar as it requires that safety-related structures, systems, and components important to safety not be shared among nuclear power units unless it can be shown that sharing will not significantly impair their ability to perform their safety functions.

(PBNP GOC 4): Reactor facilities may share systems or components if it can be shown that such sharing will not result in undue risk.

GOC 16, insofar as it requires that the containment and its associated systems (e.g.,

penetrations) be provided to establish an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment and to ensure that containment deSign conditions important to safety are not exceeded for as long as postulated accident conditions require.

(PBNP GOC 49): The reactor containment structure, including openings and penetrations, and any necessary containment heat removal systems, shall be designed so that the leakage of radioactive materials from the containment structure under conditions of pressure and temperature resulting from the largest credible energy release following a loss-of-coolant accident, including the calculated energy from metal water or other chemical reactions that could occur as a consequence of failure of any single active component in the emergency core cooling system, will not result in undue risk to the health and safety of the public.

GOC 17, insofar as it requires that onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.

(PBNP GOC 39): An emergency power source shall be provided and designed with adequate independency, redundancy, capacity, and testability to permit the functioning of the engineered safety features and protection systems required to avoid undue risk to the health and safety of the public. The power source shall provide this capacity assuming a single failure.

-4 GOC 19, insofar as it requires that equipment at appropriate locations outside the control room be provided with (a) the capability for prompt hot shutdown of the reactor, and (b) a potential capability for subsequent cold shutdown of the reactor.

(PBNP GOC 11): The facility shall be provided with a control room from which actions to maintain safe operational status of the plant can be controlled. Adequate radiation protection shall be provided to permit continuous occupancy of the control room under any credible post-accident condition or as an alternative, access to other areas of the facility as necessary to shut down and maintain safe control of the facility without excessive radiation exposures of personnel.

GOC 21, insofar as it requires that the reactor protection system be designed for high functional reliability and inservice testability commensurate with the safety functions to be performed.

(PBNP GOC 19): Protection systems shall be designed for high functional reliability and inservice testing capability necessary to avoid undue risk to the health and safety of the public.

GOC 34, insofar as it requires that a residual heat removal system be provided to transfer fission product decay heat and other residual heat from the reactor core.

(PBNP GOC 44): An emergency core cooling system with the capability for accomplishing adequate emergency core cooling shall be provided. The performance of such emergency core cooling system shall be evaluated conservatively in each area of uncertainty.

GOC 44, insofar as it requires that a system with the capability to transfer heat loads from safety-related structures, systems, and components to a heat sink under both normal operating and accident conditions be provided, and that suitable isolation be provided to assure that the system safety function can be accomplished, assuming a single failure.

(PBNP GOC 41): Engineered safety features, such as the emergency core cooling system and the containment heat removal system, shall provide sufficient performance capability to accommodate the failure of any single active component.

GOC 45, insofar as it requires provisions for periodic in-service inspection of system components.

(PBNP GOC 38): All engineered safety features shall be designed to provide such functional reliability and ready testability as is necessary.

GOC 46, insofar as it requires provisions for functional testing of the system to assure:

structural integrity, leak-tightness, operability and performance of active components, and capability of the integrated system to function as intended during normal, shutdown, and accident conditions.

(PBNP GOC 38): All engineered safety features shall be designed to provide such functional reliability and ready testability as is necessary.

- 5 GDC 50, insofar as it requires that the containment and its penetrations "accommodate, without exceeding the design leakage rate and with sufficient margin, the calculated pressure and temperature conditions resulting from any loss-of-coolant accident."

(PBNP GDC 49): The reactor containment structure, including openings and penetrations, and any necessary containment heat removal systems, shall be designed so that the leakage of radioactive materials from the containment structure under conditions of pressure and temperature resulting from the largest credible energy release following a loss-of-coolant accident, including the calculated energy from metal water or other chemical reactions that could occur as a consequence of failure of any single active component in the emergency core cooling system, will not result in undue risk to the health and safety of the public.

10 CFR 50.36(c)(2)(ii) requires that a technical specification limiting conditions for operation (LCO) of a nuclear reactor must be established for each item meeting one or more of the criteria set forth in 10 CFR 50.36(c)(2)(ii)(A)-(D).

10 CFR 50.36(c){3) requires that TSs include surveillance requirements (SRs), which 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.

10 CFR 50.48, as it requires licensees to have a fire protection plan that satisfies Criterion 3 of Appendix A to Part 50.

10 CFR 50.49, as it requires provisions for environmental qualification of electric equipment important to safety for nuclear power plants. Safety-related electrical equipment which is relied upon to remain functional during and following design basis events shall be qualified for accident (harsh) environment. This provides assurance that the equipment needed in the event of an accident will perform its intended function.

10 CFR 50.55a(f)(4)(ii), as it requires that pumps and valves which are classified as ASME Code Class 1, Class 2 and Class 3 must meet the inservice test requirements to the extent practical within the limitations of design, geometry and materials of construction of the components.

10 CFR 50.62, as it requires provisions for automatic initiation of the AFW during an Anticipated Transient without Scram (ATWS) event. In an ATWS, the AFW system shall be capable of automatic actuation by use of equipment that is diverse from the reactor trip system.

10 CFR 50.63, as it requires provisions for withstanding and recovering from a station blackout (SBO). Additional guidance provided in NRC Regulatory Guide 1.155, Station Blackout, and in NUMARC 87-00, Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors.

10 CFR 50.63 c(2), states that the alternate AC [alternating current] power source(s), as defined in § 50.2, will constitute acceptable capability to withstand station blackout provided an analysis is performed which demonstrates that the plant has this capability

- 6 from onset of the SBO until the alternate AC source(s) and required shutdown equipment are started and lined up to operate. The time required for startup and alignment of the alternate AC power source(s) and this equipment shall be demonstrated by test.

Alternate AC source(s) serving a multiple unit site where onsite emergency AC sources are not shared between units must have, as a minimum, the capacity and capability for coping with a SBO in any of the units. At sites where onsite emergency AC sources are shared between units, the alternate AC source(s) must have the capacity and capability as required to ensure that all units can be brought to and maintained in safe shutdown (non-design basis accident) as defined in § 50.2. If the alternate AC source(s) meets the above requirements and can be demonstrated by test to be available to power the shutdown buses within 10 minutes of the onset of a SBO, then no coping analysis is required.

The PBNP FSAR, Appendix A.1, SBO states in the event of a station blackout (prolonged loss of offsite and onsite AC power), the AFW system is capable of automatically supplying sufficient feedwater to remove decay heat from both units without any reliance on AC power for one hour.

10 CFR 50.65, as it requires monitoring the effectiveness of maintenance at nuclear power plants, in that preventative maintenance activities must not reduce the overall availability of the systems, structures, or components.

Regulatory Guide (RG) 1.9, "Application and Testing of Safety-Related Diesel Generators in Nuclear Power Plants," provides guidance with respect to design and testing of safety-related emergency diesel generators (EDGs).

RG 1.75, Revision 3, "Criteria for Independence of Electrical Safety Systems," describes a method acceptable to the NRC staff for complying with the NRC's regulations with respect to the physical independence requirements of the circuits and electric equipment that comprise or are associated with safety systems.

Both PBNP units were licensed to operate prior to January 1, 1979, and are required to comply with the requirements or 10 CFR 50, Appendix R, Section III.G.

The NRC staff also reviewed the analytical methodologies, assumptions, ASME (American Society of Mechanical Engineers) Code editions, and computer programs used for the structural evaluation analyses. The NRC staff's review covered structural design input parameters and design-basis loads and load combinations for normal operating, upset, emergency, and faulted conditions. The NRC staffs review also included a comparison of the resulting stresses and, where applicable, cumulative fatigue usage factors against the code-allowable limits. Specific review criteria are contained in Standard Review Plan, Sections 3.9.1, 3.9.2, 3.9.3, and 5.2.1.1, and other guidance is provided in Matrix 2 of RS-001, "Review Standard for Extended Power Uprates."

- 7

3.0 TECHNICAL EVALUATION

3.1 System Description and Summary of Proposed Changes The AFW system primary function as an emergency system is for removal of thermal energy from the primary coolant system when the MFW system is not available. The current AFW system has two MDAFW pumps, capable of 200 gallons per minute (gpm) flowrate, shared between the two units, and each unit has its own dedicated turbine-driven auxiliary feedwater (TDAFW) pump. The licensee proposes to change the design of the AFW systems by adding an additional higher capacity MDAFW pump to each unit.

The licensee proposes to install one new MDAFW pump for each unit in a new location in the primary auxiliary building (PAS). The pumps will replace the current 480 volt (V) MDAFW pumps that are currently shared between the two units with new 350 horsepower (Hp) MDAFW pumps powered by the 4160 V bus. The new MDAFW pumps will be unitized, capable of higher flow capacity, and capable of delivering flow to either or both of the unit's two SGs. The new pumps will meet the minimum flow requirement of 275 gpm at the lowest SG safety valve pressure setpoint.

Powering the AFW pumps on the 4160 V bus will relieve the current operating restrictions on the 480 V bus. The licensee stated that implementation of the AFW upgrade will require design changes to loading and sequencing on the EDGs. Upon reviewing the LAR, the NRC staff requested additional information regarding electrical distribution system analyses to evaluate EDG loading and testing, AC voltage drop, short circuit, switchgear ratings, breaker ratings, and cable design and installation to support the AFW system upgrade.

For both the MDAFW pumps and TDAFW pumps, the licensee will install an automatic swap over of the AFW pump's suction supply to the safety-related SW source upon detecting a low suction pressure while supply is from the non-seismic CST.

For both new MDAFW pumps, the licensee proposes to install a flow control valve (FCV) on the pump's discharge to each of the two individual SGs that will limit the flow to a ruptured SG in a main steam line break (MSLB) accident, thereby limiting the uncontrolled cooldown. The FCV setpoints will be set to initially provide each SG with one-half of the unit's MDAFW pump flow, eliminating the current operator action to balance AFW flow between the two units.

For each of the new MDAFW pumps, the licensee proposes to install a pneumatic back-up supply, capable of supporting operation of one FCV and one recirculation valve for the required time upon the loss of station instrument air (IA). The proposed MDAFW pumps will have shaft mounted cooling fan, eliminating the need for any external fluid to provide shaft or seal cooling, or motor cooling.

As part new MDAFW pump modification, the licensee proposes to change the direct current (DC) power supply of certain components on the TDAFW pumps in order to align the pumps with one DC train. The currently installed TDAFW pumps for each unit meet current design flow requirements with a capacity of 275 gpm, and the new MDAFW pump will not affect on the TDAFW pump flows. Therefore, the licensee states that the TDAFW pumps will continue to meet the design basis flow requirement.

- 8 The currently installed shared MDAFW pumps will remain in place; however, the licensee will not credit the pumps for mitigating any design basis event in their CLB. The pumps will only be credited for use to support emergencies beyond the design basis. The pumps will be re designated as standby steam generator (SSG) pumps.

3.2 Functional Design Requirements By regulation, those systems and components which are essential to the prevention or the mitigation of the consequences of nuclear accidents are required to be designed, fabricated, and erected to quality standards that reflect the importance of the safety function to be performed. The AFW system is designated a safety-related, seismic Class I system. The primary AFW system piping, to include the pump's suction and discharge, is required to be designed as safety-related, seismic Class I, capable of withstanding design basis earthquake accelerations without a loss of system performance capability. The design must ensure that a single active failure will not disable more than one AFW pump system in each unit, and the failure will not adversely affect the reliability of AFW function of the system. The design must provide redundancy, with a minimum of two 100 percent independent pump systems powered by diverse sources.

The licensee's FSAR, Section 10.2.1, describes in the event of a loss of normal feedwater (LONF) or loss of all alternating current (LOAC), the AFW system is required to provide a minimum of 200 gpm flow, either to one SG or split between two SGs, within 5 minutes following receipt of a low-low SG water level setpoint signal. In addition, the design capacity of the AFW system shall not let the SGs boil dry, nor shall it let primary side relieve fluid through the pressurizer relief valves, following a loss of MFW flow with a reactor trip.

Also, the AFW system shall automatically start and deliver sufficient flow to maintain adequate SG levels during accidents which require a rapid reactor coolant system (RCS) cool down in order to achieve cold shutdown conditions to remain within the limits of the analysis, i.e., steam generator tube rupture (SGTR), or a MSLB. This AFW flow is also required to the intact SG to mitigate a MSLB after a faulted SG has blown down in order to prevent the RCS from heating back up.

Also, the AFW system shall be capable of isolating the steam and feedwater lines from the ruptured or faulted SG following a SGTR or MSLB event. In the event of a MSLB, the AFW flow to a faulted SG must be limited to 400-540 gpm based upon SG pressure. The licensee's proposed AFW modification will install flow control valves on the discharge of the new MDAFW pumps to reducellimit flow to faulted SG and maintain flow to the non-faulted SG. Operator action will still be required to isolate AFW to faulted SG.

Also, the facility shall be provided with a control room from which actions to maintain safe operational status of the plant can be controlled. Adequate radiation protection shall be provided to permit continuous occupancy under any credible post accident condition or as an alternative, access to other areas of the facility as necessary to shut down the reactor, maintain shutdown, and maintain safe control of the facility.

-9 3.3 Evaluation of Proposed Changes 3.3.1 AFW System Cooling Water Supply The licensee proposes to maintain the same water supplies to the new MDAFW pump as the former MDAFW pumps. All of the AFW pumps are normally aligned to take suction from the two non-seismic CSTs, shared between the two units. The current design has one suction header routed from the CSTs to the 8-foot elevation of the control building where branch lines are provided to the existing MDAFW and TDAFW pumps. The proposed modification will retain this suction header for the TDAFW pumps and the former MDAFW pumps, now referred to as SSGs. A second separate header will be added from the CSTs to supply both new IVIDAFW pumps. In a letter dated August 9, 2010, the licensee responded to the staff request for additional information (RAI), BOP-AFW-RAI-19, concerning the design of a new supply header from the CST. The licensee stated that the safety-related transition point will be located consistent with the existing header. The license identified differences between the two headers.

The key difference being the MDAFW pumps have flow controllers; whereas, the TDAFW pumps have a fixed resistance on their discharge, resulting in higher transient flows for the TDAFW pumps. Therefore, the TDAFW pump system was used for establishing the low pressure setpoint.

The licensee credits the CST supply only during SBO conditions as the supply of water for the TDAFW pumps. The licensee is planning to increase the minimum required level to be maintained in the CST in support for the upcoming EPU. In preparation for the EPU, the licensee is requesting approval of a change in the required level in TS 3.7.6 to be maintained in the CST under this AFW modification. The new minimum required CST level will be based upon the availability of both units' CSTs. With both CSTs cross-tied or individually aligned, both CST levels must be maintained greater than or equal to 21,150 gallons. With one CST cross tied to supply both units, the CST level must be greater than or equal to 35,837 gallons. With both CSTs cross-tied to supply only one unit, the CST level must be greater than or equal to 14,100 gallons. These volumes are based upon maintaining each unit in hot shut down for one hour following a loss of all AC to afford sufficient time to align the alternate AC power source, as required by 10 CFR 50.63, NUMARC 87-00, and Regulatory Guide 1.155.

The previous minimum required CST level was 13,000 gallons per unit. The licensee is requesting a change to a higher minimum level under this AFW modification at the current power level. Since the amount of water to support the current power level has not changed, the increase in level can be evaluated as an increase in the available margin. The NRC staff has not evaluated the basis for the new specified levels for EPU conditions under this Safety Evaluation Report (SER). Therefore the staff finds the proposed increase in the minimum required levels in the CSTs to be acceptable under current licensed power conditions.

In the event the non-seismic CSTs are not available, the licensee credits a safety-related, seismic Class I, source of water from the SW system. The current license design basis assumes a supply of SWat 100 pounds per square inch gauge (psig) up to 100°F (degrees Fahrenheit) to the AFW pumps. The licensee will maintain these same design conditions when the proposed AFW modifications are completed. In a letter dated August 9,2010, the licensee responded to the staff RAI, BOP-AFW-RAI-20, concerning the adequate protection of the AFW pumps in case the supply of SW is interrupted. The licensee responded that the supply of SW is redundant and no failure is postulated that would interrupt flow of SW to the AFW pumps.

- 10 In the proposed modification the licensee will install timing circuitry that will automatically open SW valves to swap-over from the CSTs to SW upon detecting a low AFW suction pressure of 5.8 pSig. The licensee will credit this automatic swap-over to eliminate a number of operator actions associated with manually swapping AFW suction, and eliminate the current 5-minute interruption in AFW flow.

The proposed design of the automatic switchover is to detect low pressure condition in the suction piping and initiate actions to swap over the suction to SW supply to restore suction pressure prior to consumption of the available condensate water in the protected section of suction piping upstream of the service water supply connection. In a letter dated January 7, 2010, the licensee provided a timeline for the AFW suction transfer circuitry, and in a letter dated August 9,2010, the licensee responded to staff RAI, BOP-AFW-RAI-17 concerning the timing circuitry logic. The licensee selected a nominal time of 14 seconds to initiate suction transfer to ensure that the suction transfer will not be inadvertently initiated due to temporary low suction pressure that occurs during normal pump start-up transients. The licensee selected a nominal time of 21 seconds to initiate tripping of the operating AFW pumps to ensure the pumps would be secured prior to the calculated time of 25.5 seconds to deplete the condensate inventory in the protected section of suction piping if the SW transfer were to fail. In order to incorporate adequate safety margin, the licensee allows for the 3-second maximum opening time of the SW supply valve, uncertainty in the timing circuits for both initiation of suction transfer and AFW pump trip, and 75 milliseconds to reset the trip relay after full opening of the SW supply valve and associated restoration of suction pressure. Therefore, the licensee concludes that adequate margin would remain between the maximum time to restore suction pressure and the minimum time for initiation of the AFW pump trip, and an inadvertent AFW pump trip would be unlikely with SW available to the suction of the pumps.

The staff has reviewed the proposed design and finds that the proposed automatic swap-over from CST to SW supply for the suction to the AFW pumps will satisfy the assumptions in the current licensing basis for AFW flow, and will adequately protect the AFW pumps from damage if suction pressure is lost.

The new MDAFW pumps have a higher flow capacity than the currently installed MDAFW pumps; therefore, the corresponding SW requirements may be higher. The licensee evaluated the impact of these higher flow rates on the availability of SW to service other components cooled by SW during design-basis accidents (DBAs). The licensee determined the maximum SW demand occurs when decay heat removal is by the residual heat removal system rather than the AFW system. The licensee concluded that the increase in SW flow to support the new MDAFW pumps is minor, and does not adversely affect the available SW system flow required to support the containment fan coolers and other components; hence, the current analysis bounds the SW system flow requirements.

Conclusion The NRC staff reviewed the licensee's basis for AFW system cooling water supply, and finds that after the installation of the new MDAFW pumps, CST capacity and SW flow will still meet the current design basis requirements.

- 11 3.3.2 Piping and Components The licensee is installing two higher capacity MDAFW pumps to provide increased AFW flow capacity at current and EPU conditions. Also included are a new suction header from the CST to the new MDAFW pumps, and a new discharge header. The new IVIDAFW pumps must be designed to deliver the required flow at the lowest SG safety valve pressure setpoint. The current design conditions for the discharge piping for the MDAFW pumps is 1540 psig, and 1440 psig for the TDAFW pump. The pressure rating of the new MDAFW pump's discharge piping will be subject to the new pump's shutoff head; therefore, the piping must be rated for operation at a maximum pressure of 1600 psig at 100°F. The newly installed piping and valves will require a higher pressure rating than the current piping on the existing MDAFW pumps. The licensee used the original code of record, USAS B31.1 Power Piping Code, 1967 Edition, to evaluate affected piping configuration changes and associated pipe stress and supports.

In an RAI, the NRC staff asked the licensee to confirm that the pressure class ratings of new piping, valves, and components were selected for the MDAFW pumping system to meet or exceed the design service conditions. The licensee responded in the June 17, 2009, letter that design conditions for the new MDAFW pump discharge piping, valves and components up to and including the new containment isolation valves (CIVs) are 1600 psig at 100°F. Service conditions downstream of the new CIVs are based on the lower design pressure of the secondary side of the SGs (1085 psig at 556°F), which will not exceed pressures corresponding to the main steam safety valve setpoints. The licensee determined that there are no effects on the currently installed TDAFW piping with the new MDAFW pump proposed design, and the existing AFW piping and valves will remain bounded by the original design pressure.

The licensee indicated that pipe stress and pipe support evaluations due to the AFW system redeSign will be performed as part of the modification process for the AFW system. The NRC staff determined that the licensee had not provided sufficient information for the AFW review and requested that the licensee perform the required piping and pipe support design and analyses to show that the new redeSigned AFW system will maintain its structural integrity to perform its intended design function. In re~ponse to the NRC staff's RAI, the licensee performed the evaluations and submitted the upgraded AFW system structural evaluation summaries in letters dated November 21, 2009, and January 8 and July 23, of 2010.

In response to staff's RAI, the licensee has shown that it has evaluated the AFW structural integrity in accordance with the USAS B31.1, Code for Pressure Piping, 1967 Edition which is the PBNP original code of construction. The licensee indicated that because USAS B31.1-1967 does not expressly identify how to incorporate earthquake effects, the original design at PBNP used ASME Section III rules as guidance. A formal pipe code reconciliation study was performed and documented by Impell Corporation, which reconciled USAS B31.1-1967 to ASME Section III, 1977 Edition with Addenda through Winter 1978. The licensee also stated that "ASIVIE Section 111-1977 was also used for the PBNP As-Built Reconciliation Program for NRC Bulletin (IEB) 79-14, Seismic Analyses for As-Built Safety-Related Piping Systems, which is the current design basis." The staff in its review found that the licensee used ASME Section 111 1977 equations for load combinations to calculate pipe stresses due to internal pressure, deadweight, seismic and thermal expansion and compared the calculated values to the original code of construction (B31.1-1967) allowable values, which the staff finds acceptable. For the AFW pipe support structural evaluation, the licensee used the American Institute of Steel Construction Steel Construction Manual Ninth Edition which, as the licensee stated, is

- 12 consistent with the current design basis for PBNP. Therefore, the staff finds the licensee's methodology of pipe and pipe support structural evaluations acceptable.

The NRC staff's review also included a comparison of the resulting stresses against the code allowable limits. The licensee, using current plant design basis, evaluated the structural adequacy of the upgraded AFW piping system and components for pressure, deadweight, thermal expansion and seismic loads. The licensee provided a discussion which shows that these loads (used in the pipe stress analyses) are applicable for current license thermal power (CL TP) and EPU conditions. Letter dated November 21, 2009, contains load combinations for piping analysis, pipe supports, equipment nozzles and penetrations, which are in accordance with the current design basis. Maximum pipe stress summaries, including stress summaries for the tie-in locations to the existing AFW system, show that the calculated pipe stresses (for CL TP and EPU conditions) are within the allowable limit values of USAS B31.1-1967, which is the original code of construction and current design basis code of record. The stress summaries provided by the licensee also show that the calculated stresses for the condensate storage tank nozzles for the MDAFW suction and recirculation lines are within allowable values, while the nozzle loads for the turbine-driven AFW pumps have not changed or are not affected by the AFW system modification. Based on the above the NRC staff finds that the structural integrity of the AFW system with its proposed modifications is adequate for CL TP conditions.

In response to staff's RAI, the licensee stated that the pump vendor. using bounding suction and discharge pump nozzle loads from piping, found the MDAFW pump stresses within the code allowable values. In addition, the licensee completed calculations required to ensure that the code allowable values are satisfied with sufficient margin, to allow for as-built configuration changes required to meet field conditions. In a closing response to the staff's RAI, the licensee stated that piping and pipe supports affected by modifications to the AFW system have been evaluated and remain structurally adequate for both CL TP and EPU conditions. Based on the discussion above, the NRC staff finds this acceptable.

The licensee, using the current plant licensing and design basis methodology and acceptance criteria, has evaluated the structural integrity of the upgraded AFW system piping, equipment nozzles and supports and has found them structurally acceptable for CL TP and EPU conditions.

It is though noted that due to changes in methodology by the PBNP's high-energy line break (HELB) Reconstitution, the licensee has identified additional pipe break postulated locations in the PBNP AFW steam lines, the effects of which, according to the licensee's statements in letter dated December 21,2010, have been evaluated and have no adverse impact on essential equipment. The NRC staff's review of the PBNP HELB reconstitution under EPU conditions is provided in a separate correspondence and it has concluded that there is no adverse impact on essential equipment as a result of pipe whip and jet impingement from postulated pipe failures.

Based on its review as summarized above, the NRC staff finds the licensee's structural evaluations for the AFW proposed modification acceptable for CL TP and EPU, as they conform to the codes of record and plant design basis requirements.

Conclusion The NRC staff reviewed the licensee's upgraded AFW modification evaluations related to the structural integrity of piping, components, and supports. For the reasons set forth above, the NRC staff concludes that the licensee has adequately addressed the effects of the CL TP and

- 13 the proposed EPU on the structural integrity of the upgraded AFW piping. components, and supports.

Based on the above, the NRC staff concludes that the licensee has provided reasonable assurance that the modified AFW system, following installation of the new MDAFW pumps, will continue to be structurally adequate to perform its intended safety-related design function for CL TP conditions.

3.3.3 Pumps and Valves In support of the proposed AFW modification, the licensee is installing new MDAFW pumps, piping and valves to make the new MDAFW pumps unit specific. The pumps and valves are required to meet inservice testing (1ST) requirements.

In the current design. the licensee credits each AFW pump system having two ways, using power from the opposite train, to stop AFW flow for events that require AFW flow to be terminated. The staff requested the licensee to verify that the new AFW system will still provide the safety function of two diverse ways to stop flow when required. In a letter dated, November 21,2009, the licensee response stated that the new MDAFW pump system will have two diverse ways to accomplish the isolation function, either by closing the FCV to the affected SG, via 120 V AC power in conjunction with a backup pneumatic system, or the operator can trip the MDAFW pump via a diverse 125 V DC pump control power. In regards to the TDAFW pump system, the licensee stated that flow from can be isolated by closing the pump's discharge valve associated with the affected SG using 125 V DC control power, or by tripping the TDAFW pump via a diverse 125 V DC supply to the trip throttle valve. Therefore, the licensee contends they have maintained two diverse ways to stop flow in the proposed design.

Safety-related pumps and valves are required to be a part of the licensee's 1ST program. The licensee's 1ST program document details the technical basis and overall description of the activities planned to fulfill the 1ST requirements as required by 10 CFR 50.55a(f)(4)(ii) and their CLB. The licensee has committed to adding the pumps and valves associated with the proposed AFW design into their 1ST program.

The currently installed MDAFW pumps will remain in place, but they will become SSG pumps.

The licensee states that all AFW system automatic start signals to the SSG pump trains will be removed. The SSG pumps will still be powered from safety-related AC power, but will no longer automatically start or load to the EDG. If running, the pumps will be stripped from the bus upon an AFW initiation signal or diesel safeguards sequence signal. All controls for the SSGs and their associated valves will be limited to manual operation. To prevent inadvertent starting of an SSG pump while the new MDAFW pumps are operating. restart of a tripped SSG pump requires administrative controls and manual action by the operator. The licensee states that there will not be any sharing of pumps or active valves between the SSG trains and the credited AFW systems. A check valve on the SSG discharge will prevent any back flow from the new MDAFW pump system.

As part of the new MDAFW pump modification the licensee evaluated minimum recirculation flow, suction piping vortexing, and available net positive suction head (NPSH). The licensee states the proposed modification will include a minimum recirculation flow line back to the CST with the capability of 100 gpm, which will meet the vendor recommendations. The MDAFW pump recirculation valves will open when the pump starts and will close within the

- 14 predetermined time delay of the pump forward flow rate reaching the established setpoint. The recirculation valve will be designed to fail close on loss of air, but will receive air from the safety related backup air supply. The licensee proposes to add a second CST suction header with its own CST nozzle at the same elevation, supplying the new MDAFW pumps. The NPSH is affected by the higher AFW flow with the new MDAFW pump. The licensee's evaluation determined the most limiting available NPSH condition for the AFW pump suction occurs when the CST is at its lowest level. In a letter dated June 17, 2009, in response to RAI Question 12, the licensee confirmed that their calculation shows adequate NPSH will be available to the AFW pumps when the water level is well below the centerline of the CST nozzle elevation. Therefore, licensee concludes that the new minimum CST levels will ensure adequate NPSH, that vortexing will not occur, and the minimum recirculation line will adequately protect the pump.

Conclusion After reviewing the licensee's proposed design and RAI responses, and based on the discussion above, the staff finds that the licensee proposal for these two independent MDAFW pumps meets the requirements for safety-related pumps and valves in accordance with 1ST requirements specified in 10 CFR 50.55a(f)(4)(ii) and their CLB.

3.3.4 Electrical The licensee's proposed modification will replace the currently installed 250 Hp, 480 V, MDAFW pump motors with new 350 HpJ 4160V pump motors. Repowering the AFW pumps on the 4160 V bus will relieve current operating restriction on the 480 V bus. The new pumps will affect the loading of the emergency bus and fuel requirements.

The licensee deemed the existing TDAFW pump system as adequate; however, the licensee is making changes to the TDAFW pump system, limited to re-powering valves on the DC busses to make the pump trains independent. In those instances where DC power is required to support operation of the new MDAFW pump (e.g, control power to the 4 kV switchgear), the licensee will provide a DC power source that is diverse from the DC supply associated with the Unit's TDAFW pump. Once the modifications are complete, the TDAFW pump and its associated valves will be powered from one DC train, and the MDAFW pump with its associated valves will be powered from the other DC train. The licensee is proposing this new configuration in order to gain train independence.

The NRC staff noted in the PBNP FSAR that the steam supply and AFW discharge valves were powered from diverse sources of vital 125 V DC. The licensee proposes to modify the valves powered by the DC busses, which will change the "diverse" strategy the licensee credits in their FSAR. The staff requested the licensee provide the basis for the original design powering the TDAFW pump with diverse DC power supplies, and the justification for repowering the components from a different bus. In a letter dated November 21, 2009, the licensee explained that part of the modification will move one of the Unit 1 TDAFW pump's steam supply valve and one FCV to the SG from the "B" bus, D02, to the "A" bus, D03. The modification will move one of the Unit 2 TDAFW pump's steam supply valve and one feedwater control valve to the SG from the "A" bus, D03, to the "B" bus, D04. The end result will be the Unit 1 TDAFW pump will be powered by the "A" DC train, and the Unit 2 TDAFW pump will be powered by the "B" DC train. Therefore, powering the Unit 1 and Unit 2 TDAFW pumps using the "A" and "8" train DC buses, respectively, still utilizes two different DC buses, with each bus providing a success path to allow steam admission to the TDAFW pump and feedwater control to a SG. The licensee

- 15 states, "This approach maintains the diversity of power supplies consistent with FSAR Section 10.3.2 and continues to meet commitments associated with 10 CFR 50.48 and 50.63."

The NRC staff reviewed the licensee's response and conducted an in-depth discussion with the licensee at the site. The proposed modification changes diversity from two different DC trains, to two different DC buses on the same DC train. Since the two DC buses on the same DC train are independent, the staff concurs that diversity is maintained.

4160 V and 480 Volts Aternating Current (VAC) Systems The licensee used Electrical Transient Analysis Program (ETAP) to analyze the most limiting motor terminal voltage using the new total cable length for steady-state running voltage and motor starting voltage for train A and B MDAFW pumps. The results of this analysis confirmed adequate voltage at the motor terminals. In addition, a review of the available short circuit currents as a result of the new motors, the 4160 V switchgear and breaker ratings exceed the available short circuit fault currents. The licensee's cable amperage capacity calculations indicate that power cables connected between the new MDAFW pumps and their sources of electric power, 4160 V switchgear, are sized and protected consistent with PBNP FSAR, Section 8.0.1, "Principal Design Criteria." The results of the licensee's protective coordination calculation show that both the motors and their power supply cables are protected against both overload and short circuit and that the MDAFW pump breakers properly coordinate with their upstream breakers.

Direct Current Power The NRC staff also reviewed the impact on Class 1 E DC system as a result of the AFW modifications. PBNP FSAR Section 8.7 states that the safety-related 125 V DC system consists of four main distribution buses: D-01, D-02, D-03, and D-04. The D-01 (train A) and D-02 (train B) main DC distribution buses supply power for control, emergency lighting, and the red and blue 120 VAC Vital Instrument bus (Y) inverters. The D-03 (train A) and D-04 (train B) main DC distribution buses supply power for control, in addition to the white and yellow 120 VAC Vital Instrument (Y) buses. Where DC power is required to support operation of the new MDAFW pump (e.g., control power to the 4160 V switchgear), the DC power source is diverse from the DC supply associated with the Unit's TDAFW pump. Once the modifications are complete, the TDAFW pump and its associated valves will be powered from one DC train, and the MDAFW pump with its associated valves will be powered from the opposite DC train, thus maintaining the independence and redundancy of the AFW system.

PBNP FSAR Section 10.2.3 states that the steam supply and AFW discharge valves are powered from diverse sources of vital 125 V DC. In letter dated, October 22, 2009, the NRC staff requested the licensee to provide the basis for the original design powering the TDAFW pump with diverse DC power supplies, and the justification for repowering the components from a different bus. In a letter dated November 21, 2009, the licensee explained that part of the modification will move the Unit 1 TDAFW pump's steam supply valve and feedwater control valve to the SG from the "Bn Train, D-02, to the "An Train, D-03 and will also move the Unit 2 TDAFW pump's steam supply valve and feedwater control valve to the SG from the "An Train, D-03, to the "Bn Train, D-04. The end result will have the Unit 1 TDAFW pump being powered by the UA" DC Train, and the Unit 2 TDAFW pump being powered by the "B" DC Train. This approach maintains the diversity of power supplies consistent with FSAR Section 10.2.3. The separation of power supplies into two independent trains for the TDAFW pumps and valves

- 16 maintains separation criteria for fire protection and supports the capability of each TDAFW train to maintain station blackout requirements. Therefore, the proposed design continues to meet commitments associated with 10 CFR 50.48 and 50.63.

The NRC staff agrees that powering the Unit 1/2 TDAFW pump using the "A"rB" train DC buses, respectively, with each bus providing a success path to allow steam admission to the TDAFW pump and feedwater control to a steam generator meets the 10 CFR 50.48 and 50.63 regulatory requirements for ensuring the capability to shut down the plant by providing adequate independence and redundancy during fire or loss of AC power. In response to the staff's RAI regarding maintaining redundancy with the MDAFW and TDAFW DC power and control circuits, the licensee letter dated AUgust 6, 2010, confirmed that each unit is provided with two safety related AFW pumps, each of which is furnished electrical power from redundant and independent sources of power. The staff finds the licensee's response acceptable.

Emergency Diesel Generator The EDG configuration consists of four shared EDGs. The EDGs are divided into two trains, "An (1 A and 2A) and "B" (1 Band 2B). The NRC staff questioned whether the EDG loading calculation accounted for loading such as cable losses, voltage and frequency variations, and other load additions as a result of the proposed EPU and alternative source term (AST) amendments, and if so, how the loads being added would affect the capability and capacity of the EDGs. The licensee in its June 17, 2009, letter provided evaluations of the worst-case loadings to be 2801 kilowatts (kW) and 2800 kW for Units 1 and 2 Train A EDGs, respectively, and 2877 kW and 2874 kW for Units 1 and 2 Train B EDGs, respectively. The licensee concluded that the Train A EDGs will continue to operate within their 2000-hour rating of 2850 kW and Train B EDGs will continue to operate within their 200-hour rating of 2,951 kW for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and then remain within their 2,000-hour rating of 2,848 kW for the most limiting design-basis accident EDG electrical loading condition.

The NRC staff noted that PBNP Units 1 and 2 do not currently have a TS SR for demonstration once per shutdown/refueling interval that the EDGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Since PBNP's EDG worst-case loading is in the emergency load ratings of the EDG, the staff asked the licensee how it demonstrates the EDG's capability for sustained operation for its mission time since the existing TS 3.8.1 does not specify any endurance and load margin test (24-hour test) reqUirements. Based on review of the current industry operating experience, the NRC staff noted that plants with 24-hour endurance runs identified degraded component performance resulting from EDG excess loading requirements and maintenance or system modification deficiencies that would not have been identified by plants with no endurance and load margin test TS testing requirements. In response to the NRC staff's concern, the licensee submitted Supplement 2 to LAR 261 dated June 17, 2009, stating that a 24-hour capability test should be performed on the A and B Train EDGs to demonstrate the capability of the EDGs for these revised worst case loadings. This supplement proposes to add a new 18-month TS SR for the EDGs.

- 17 Surveillance Requirement 3.8.1.7, The licensee proposed adding TS SR 3.8.1.7 as follows:

SURVEILLANCE FREQUENCY SR 3.8.1.7

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

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

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

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

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

18 months

a. For ~ 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded to ~ 2800 kW and s 2875 kW (GOI/G02), ~ 2875 kWand s 2950 kW (G03/G04)

b. For the remaining hours of the test, loaded

~ 2565 kW and S 2850 kW.

The proposed change to TS 3.8.1, "AC Sources - Operating," adds this new SR 3.8.1.7 to verify each DG operates for ~ 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months with a FREQUENCY of 18 months. The test protocol requirements for this surveillance are added as SR 3.8.1.7 as follows:

a. For ~ 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded to ~ 2800 kW and S 2875 kW (GOI/G02), ~ 2875 kWand S 2950 kW (G03/G04), and

b. For the remaining hours of the test loaded ~ 2565 kW and S 2850 kW.

The NRC staff noted that the proposed EDG endurance and margin test does not envelope the accident loads for the entire duration of the 24-hour run and does not meet the recommendations in RG 1.9, "Application and Testing of Safety-Related Diesel Generators in Nuclear Power Plants." Specifically, EDGs G-01 and G-02 are loaded only to 98.2 percent to 100.9 percent of the 2000-hour load rating for 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months and 90 to 100 percent of the 2000-hour load rating for the remaining 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months ; G-03 and G-04 EDGs are loaded to 97.4 percent to

- 18 100 percent of the 200-hour load rating for 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months and 90 to 100 percent of the 2000-hour load rating for the remaining 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months with EDGs operating at the highest end of the 2-hour load range for 5 minutes. RG 1.9 recommends that for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , EDGs are loaded to 105 to 110 percent of the EDG's continuous rating, and 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months at a load equal to 90 to 100 percent of the generator's continuous rating. The intent of the 24-hour test is to demonstrate that the EDG can operate at maximum postulated accident loads for an extended duration. The 2-hour test requirement at a higher loading demonstrates design margins. Therefore, staff requested the licensee to demonstrate why the proposed loading ranges are adequate to show the capability of the EDGs to operate for its intended mission time. In its response dated April 15, 2010, the licensee states that:

To improve margin to the 2000-hour rating for the EDGs, NextEra initiated modifications to remove unnecessary loads from the EDGs. These modifications will be implemented as part of the AST [alternative source term] modifications. [The licensee identified this as a regulatory commitment]. The modifications will further reduce the worst case design basis loads for Train "B" EDGs as noted above. A minor increase in worst case loads for Train "An EDGs was identified as a result of the revised calculations. This minor increase for Train "An occurred because sufficient capacity to manually start a component cooling water pump instead of a charging pump resulted when loads were removed from Train "A". The lower power charging pump was previously available without exceeding the 2000-hour rating for the Train "A" EDGs. The modifications to remove unnecessary loads from Train "A" EDGs resulted in sufficient capacity to support starting the component cooling water pump, which might be preferred depending on operating conditions. These design modifications will result in revised EDG loading as follows:

Train A Train B G-01 G-02 G-03 G-04 Worst Case Load 2817 kW 2817 kW 2831 kW 2831 kW 2000-hour Rating 2850 kW 2850 kW 2848 kW 2848 kW Margin to 2000-hour Rating 33kW 33kW 17 kW 17 kW The NRC staff determined that based on the revised loading on the EDGs, the worst case loads on both Train A and B EDGs are within the 2000-hour rating of the EDGs. The licensee also revised the proposed TS SR 3.8.1.7 previously submitted as discussed above.

The proposed change to TS 3.8.1, adds new SR 3.8.1.7 which states to verify each standby emergency power source operates for 2:: 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at 2:: 2850 kW (G01/G02), and 2:: 2848 kW (G03/G04). The frequency is 18 months.

The following NOTES are added to SR 3.8.1.7:

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

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

- 19

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

Basis for the Proposed Change:

The performance of a 24-hour endurance and load margin test of each EDG at 18-month interval is consistent with industry practice for plants such as PBNP with 18-month refueling intervals. This is also consistent with NUREG-1431, Standard Technical Specifications, Westinghouse Plants. Specifically, the proposed new surveillance is consistent with SR 3.8.1.14 of NUREG-1431.

The NOTES for the proposed SR 3.8.1.7 are also consistent with NUREG-1431, with the exception of the first sentence of NOTE 2, which has been deleted in the proposed SR3.8.1.7. The first sentence of NUREG-1431 SR3.8.1.14, NOTE 2 states that: "this surveillance is normally not performed in MODES 1 or 2." At PBNP, the standby emergency power sources are train-specific rather than unit-specific. As a result, each standby emergency power source is available to be lined up to either or both units. At least one reactor at PBNP is normally operating in MODE 1, although the other reactor may be shut down. Therefore, it is not practical to perform this surveillance on an 18-month interval with both units shut down. PBNP has been performing 24-hour standby emergency power source load testing on a 24-month frequency safely with both units typically operating in MODE 1. The test protocol requirements in proposed SR 3.8.1.7 were developed to demonstrate the capability of the standby emergency power sources to carry worst case loads for the extended power uprate, AST, and AFW system upgrades without causing unnecessary wear and reduction of long-term reliability of engine components due to testing. The specific test requirements are generally consistent with the requirements of NUREG-1431 SR 3.8.1.14, but reflect that the worst case loads determined for the Train A EDGs and Train B EDGs are close to the 2000-hour rating.

The NRC staff noted that the proposed 24-hour test does not demonstrate the design margin of the EDG as recommended in RG 1.9 since the 2-hour portion of the 24-hour test is not loaded to 105-110 percent of the EDGs continuous rating. The staff requested the licensee to provide justification why the proposed loading ranges are adequate to demonstrate the design margins of the EDGs to operate for its intended mission time. The licensee in its letter dated August 9, 2010, stated that the actual loads are expected to be lower than the maximum design basis loads based on the significant conservatisms used to develop the worst-case design basis loading. Conducting the surveillance at the 2850 kW (or 2848 kW for G03 and G04), 2000-hour load rating, demonstrates that the EDG will carry more than the projected load, yet balances surveillance testing requirements against the increased maintenance requirements that would apply, if the EDG is tested at higher loads. The increased maintenance would result in increased out of service time. Therefore, the surveillance test load value is an appropriate balance between demonstrating reliability with some margin allowance and not incurring increased unavailability by having to perform additional maintenance, if the EDG were tested at higher load values. The staff determined that although the proposed test does not meet the 2-hour portion of the endurance test in accordance with the guidance provided in RG 1.9, the proposed 24-hour test is acceptable based on the consideration that it will demonstrate that the EDG can operate above the maximum postulated accident loads for extended duration with some margin. Also, since the standby emergency power sources are train-specific rather than

- 20 unit-specific, the remaining EDGs would remain operable and is independently capable of mitigating a Design-Basis Accident (DBA) or providing power for safe shutdown of the associated unit, while the EDG is tested during Mode 1.

EDG Voltage The NRC staff noted that Train B EDG bus voltages remain above 75 percent of nominal voltage, consistent with RG 1.9, throughout the motor starting sequence in all postulated loading conditions. In response to the staffs RAI dated August 26,2009, regarding EDG voltage dip below the acceptance limit of 75 percent nominal voltage during motor start for Train A EDG, the licensee stated that the EDGs are capable of starting safeguard loads, and the voltage recovers quickly to the acceptable level. Based on its review of the licensee's dynamic loading calculations, the staff noted that under certain loading conditions for Train A EDG, the frequency is outside the 2 percent margin, the worst-case voltage dip is 45-48 percent, and the voltage overshoot is 129.5 percent. The voltage and frequency variations for Train A is outside the industry accepted standards and guidance. Therefore, the staff requested the licensee to provide detailed analyses regarding the downstream effects on components such as contactors, control fuses, inverters, battery chargers, solenoids, motor-operated valves, solid state devices, etc., and the basis to show that all required loads will start and continue to run with sufficient margins after accounting for any uncertainties during a DBA In response to the NRC staff concerns, the licensee submitted letter dated April 15, 2010, stating that a dynamic loading calculation for each EDG was performed to demonstrate that each EDG is capable of performing its specified safety function. The licensee also states that as part of the detailed design phase of the AFW project, the following change was made to the AFW design that will improve the EDG dynamic response:

Starting of the new AFW pump was changed from a random load to a fixed load block at 32.5 seconds after EDG breaker closure. This design change from a random start of the AFW pump improves the EDG voltage response profile by preventing interaction with existing load blocks and moving the AFW load block beyond the present 10.5 seconds load block and the service water pump load blocks. This will improve plant response by reducing design basis accident Loss of Offsite Power/Loss of Coolant Accident (LOOP/LOCA) motor-operated valve (MOV) response times and prevent the AFW pump from starting simultaneously with the service water pumps and the containment spray pump during a large break LOCA Starting the AFW pumps at 32.5 seconds after EDG breaker closure meets the AFW design basis requirements. The EDG dynamic model was compared to the actual EDG response during integrated safeguards testing conducted to ensure that the model conservatively envelopes the actual EDG response.

The licensee also states that the revised analysis demonstrates the following:

1. The minimum voltage for the AFW pump start at 32.5 seconds during the large break LOCA is approximately 75 percent of nominal 4160 V bus voltage on the Train A EDGs G-01 and G-02, and

2. The performance capabilities of the Train "Al! EDG voltage regulator and excitation system supporting required equipment are within design basis requirements following a design-basis accident (DBA).

- 21 The Train "A" and "B" EDGs are capable of successfully sequencing all required electrical loads for the DBA loading on the EDGs, including the loads for the upgraded AFW system and alternative source term (AST) modifications. The overall minimum EDG voltage is not affected by the new AFW design and continues to occur in the initial EDG load block. For accidents where the containment spray pump start may be delayed, the potential simultaneous start of the containment spray pump and the AFW pump has been evaluated and found to be acceptable.

Based on its review of the licensee's analysis, the NRC staff was concerned that the licensee's EDG dynamic model validation may not be conservative since it was compared to the response from an integrated safeguards testing when some of the larger pumps were operating in recirculation mode resulting in faster acceleration time. The EDG response during a worst case accident loading condition may be slower. Therefore, the staff requested the licensee to verify that the performance capabilities of safe shutdown equipment when the EDG is operating with fully loaded motor loads for the limiting DBA with sufficient margin. In its response dated August 9,2010, the licensee states that the model in ETAP software, utilized to perform the EDG transient analysis, results in a conservative analysis because the model is conservatively tuned to provide bounding equipment models for DBA loading conditions. In addition, the licensee states that the transient analysis calculation documents the motor demand factors for expected motor loads during surveillance tests, and design basis events, and the maximum demand factors are based upon calculated flow conditions during worst-case design basis LOOP/LOCA transients. Based on this information, the staff concludes that the licensee has demonstrated the performance capabilities of safe shutdown equipment, when the EDG is operating with fully loaded motor loads for the limiting DBA with sufficient margin.

In response to staff's RAI regarding the effects on downstream components during load sequencing, the licensee stated that it had addressed the effects on components such as contactors, control fuses, inverters, battery chargers, solenoids, MOVs, and solid state devices resulting from the EDG dynamic response to design basis loading conditions. The licensee's analysis is based on vendor supplied equipment ratings and concluded that all required loads will start and continue to run with sufficient margins after accounting for any uncertainties. The licensee also stated that "The dynamic EDG loading calculation results show that there is an initial delay in energizing the MCC [motor control center] loads when the EDG output breakers close because the initial voltages are below the pickup requirements of the 480 V MCC contactors. The voltage recovers above the pickup requirements of the contactors to start the required loads. In addition, the MCC contactors on Train "A" also drop below their holding voltage requirements during the loading sequence when two switchgear motors start simultaneously. This occurs only when containment spray pumps have a delayed motor start.

The voltage recovers above the pickup requirements of the contactors to re-start the required loads. The loads are capable of restarting and operating to meet design bases requirements."

The staff requested the licensee to verify that all loads are capable of restarting and operating for the limiting or bounding case. In its response dated August 6,2010, the licensee confirmed that all loads will meet their intended safety functions as assumed in the accident analYSis based on reviewing certain downstream loads. However, the staff was not certain that the limiting components were evaluated to confirm that all downstream loads such as contactors, control fuses, inverters, battery chargers, solenoids, MOVs, and solid state devices resulting from the EDG dynamic response to design basis loading conditions have adequate voltage when fed from EDG A.

- 22 The NRC staff held a public meeting with licensee in October 27,2010, to understand the performance capabilities of limiting components during a design basis event coupled with a loss of offsite power. In its letter dated November 12, 2010, the licensee provided details on limiting loading conditions for pumps and motors included in the ETAP modeling of the electrical equipment and margins available in the stroke times of critical valves. Specifically, the licensee stated that high head and low head safety injection (SI) pumps have been modeled using the maximum brake horsepower (BHP) that the pumps are capable of drawing, the containment spray pumps were simulated close to run out conditions and the SW pumps were modeled to ensure that the calculated BHP requirements for the SW pumps conservatively bound the worst-case emergency power loading conditions for the system. The licensee further stated that effects of EDG frequency variation of +/-0.3 Hertz were accounted for in the analysis of large motors and stroke times of critical MOVs. In addition, the performance capabilities of critical MOVs were evaluated in detail to confirm that either the MOVs will complete their full stroke prior to a stall or that if MOV stall events occur, the MOV has sufficient excess torque capability to complete its stroke once the voltage is restored and no damage to the MOV will occur. This evaluation was performed by the licensee for each affected MOV. The licensee has concluded that MOVs with critical stroke times have adequate margin to ensure that flow rates assumed in accident analyses will not be adversely impacted and that the MOVs will not be damaged by potential motor heating as a result of potential stall conditions when voltage drops occur during operation.

The staff had previously requested clarification on performance of thermal overload protection devices associated with equipment that may stop and start during transient low voltage conditions. The licensee has stated in its November 12, 2010, letter that thermal overload devices were evaluated for two consecutive starts on components that may trip and restart during EDG voltage swings and that protective devices will not operate inadvertently during undervoltage and overvoltage conditions associated with EDG loading transients.

The staff finds the licensee's response acceptable based on the following: (1) the large motors were conservatively modeled for worst case EDG loading and voltage drop analyses, (2) the EDG frequency variation was adequately considered in the analysis, (3) the operation of critical MOVs was evaluated in detail for meeting the stroke time requirements consistent with accident analysis assumptions, and (4) potential for stalling and overheating during voltage transients were evaluated and confirmed that all MOVs will be capable of performing their safety functions during load sequencing on the "A" Train EDGs.

EDG Fuel Oil Requirements In LAR 261, Section 2.5.7.1.3, the licensee states that "PBNP has reviewed the assessment related to the amount of required fuel oil for the EDGs and concludes that the assessment has adequately accounted for the effects of the increased electrical demand on fuel oil consumption.

PBNP concludes that the EDG Fuel Oil Storage and Transfer system will continue to provide an adequate amount of fuel oil to allow the diesel generators to meet the onsite power requirements of PBNP GDCs 4, 39, and 40." In response to the staff's questions regarding how the EDG fuel oil consumption and volume calculation accounted for additional fuel oil requirements for AFW and other plant modifications, the licensee stated the following in its response dated March 3, 2010:

The EDGs will remain within their rated loads with EPU, AFW, and alternative source term (AST) load additions. The EDG fuel oil consumption calculation determined

- 23 fuel oil requirements based on the applicable EDG rated loads. Fuel oil consumption during the first 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months of operation for Train A EDGs is based on the 2000-hour rating of the EDG.

Consumption during the first 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months of operation for Train B EDGs is based on the 195-hour rating. Fuel oil consumption for 7 -day operation is based on the 2000-hour rating for Train A EDGs and the 195-hour rating for the first two days of Train B EDGs combined with 2000-hour rating for the remainder of the 7 days. Calculations have demonstrated that with the EPU, AFW and AST modifications, the EDG loading would be within the rated load.

The initial sizing of the EDG G-03 and G-04 fuel oil day tanks was based on a nominal fuel consumption rate and included a 10 percent margin. The revised EDG fuel oil consumption and volume calculation transmitted by letter dated September 25, 2009, used a more accurate determination of the fuel oil consumption rate based on EDG performance testing with corrections for specific gravity based on PBNP Fuel Oil Acceptance Criteria and a correction for the use of Ultra Low Sulfur Diesel fuel. The 10 percent margin was provided for initial tank sizing and is not considered applicable to subsequent capacity evaluations.

The staff considers that the onsite fuel oil storage shall be sufficient to operate the diesel generator following any design basis event for seven days. The staff requested the licensee to explain why the 7 -day fuel oil requirement, as discussed in the PBNP licensing basis documents, is not factored into the TS-controlled bounding fuel oil volume requirements. In addition, the staff requested the licensee to clarify if the 10 percent margin has been removed from the fuel oil storage required on site for 7-day operation of EDGs.

In a letter dated March 3, 2010, the licensee stated that the initial sizing of the EDG fuel oil day tanks was based on a nominal fuel consumption rate and included a 10 percent margin. The revised EDG fuel oil consumption and volume calculation used a more accurate determination of the fuel oil consumption rated based on EDG performance testing with corrections for specific gravity based on correction for the use of Ultra Low Sulfur Diesel fuel. The 10 percent margin was provided for initial tank sizing and is not considered applicable to subsequent capacity evaluations.

The NRC staff is evaluating a January 27,2010, LAR (ADAMS Accession No. ML100280230) to revise TS 3.8.3 as it pertains to the EDG fuel oil storage tanks. The requirements for fuel oil storage, controlled under TS 3.8.3, will be resolved by the NRC staff in response to the LAR.

The proposed changes will increase the fuel oil stored in safety-related tanks. The NRC staff considers the proposed changes to the PBNP TSs provide reasonable assurance of the continued availability of the required electrical power to shut down the reactor and to maintain the reactor in a safe condition after an anticipated operational occurrence or a postulated design-basis accident.

Surveillance Requirement 3.3.4.3, Loss of Voltage (LOV) Time Delay Channel Calibrations The NRC staff in the Electrical Engineering Branch evaluated the LOV relay settings for the safety-related 4160 V buses and non-safety related 4160 V buses and determined that the existing LOV relay time delays are not adequate to ride through a grid disturbance at EPU

- 24 conditions. The TS 3.3.4 "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation" will be revised to incorporate new LOV time delay allowable values for safety-related buses.

Specifically, SR 3.3.4.3.a. will be revised from, "with a time delay of=::: 0.7 seconds and s 1.0 second," to "with a time delay of =::: 1.8 seconds and S 2.3 seconds (Bus Loss of Voltage Relay) and =:::1.95 seconds and S 3.55 seconds (EDG Breaker Close Delay Relay)" and SR 3.3.4.3.c will be revised from "with a time delay of S 0.5 seconds" to "with a time delay of

=::: 1.15 seconds and S 1.6 seconds."

In response to staff's RAI related to the impact of increasing the time delay for the LOV relays and EDG breaker closure time on performance of equipment operating under degraded voltage conditions for extended duration and accident analyses, the licensee, in letter dated April 28, 2010, stated that a detailed analyses had been performed for the proposed changes to TS 3.3.4. The licensee concluded that:

The maximum allowable time delay was established to ensure the satisfactory operation of equipment would occur without tripping over-current protective devices when the voltage is below the DV [degraded voltage] relay setpoint but above the LOV relay setpoint.

Over-current protective device will not trip as a result of the higher current from the motors operating at just above the LOV relay setting for at least 48 seconds.

The time delay associated with the EDG breaker close delay relay still ensures the time requirements of the PBNP FSAR Chapter 14 accident analyses remain valid.

In the event of voltage conditions below the degraded voltage relay setpoint and no safety injection signal, the equipment is expected to operate as designed and the equipment response time for accident analyses remains valid.

The time delay for the LOV relays is adequate to ride through transient low voltage conditions during EDG loading when responding to an accident signal.

Based on the licensee's responses to the staff's RAI, the NRC staff finds the proposed changes to TS 3.3.4 are acceptable.

License Conditions The licensee is changing plant configuration as part of the AST, AFW system modifications, and power uprate. The NRC staff's evaluation is based on the successful implementation of plant modifications that resolve the following license conditions:

NextEra Energy Point Beach, LLC shall modify the motor-driven auxiliary feedwater and the turbine-driven auxiliary feedwater pump systems to ensure they are powered from independent DC power source.

NextEra Energy Point Beach, LLC shall implement modifications to reduce emergency diesel generator (EDG) loading such that the maximum loading will not exceed the 2000-hour rating of the EDGs.

- 25 NextEra proposed the license conditions in its letter dated November 1, 2010. The licensee specified the implementation date for these license conditions as prior to the end of the Unit 2 refueling outage in the spring of 2011.

Conclusion Based on the above evaluation, the NRC staff finds the proposed changes to the TSs provide assurance of the continued availability of the required power to shut down the reactor and to maintain the reactor in a safe condition after an anticipated operational occurrence or a postulated DBA. The NRC staff also concludes that the proposed TS changes are in accordance with 10 CFR 50.36,50.49,50.63, and 50.65; meet the intent of the PBNP GDCs 19 and 39; and are consistent with the guidance in RG 1.9 and 1.75. Therefore, the NRC staff finds the proposed changes acceptable.

3.3.5 Instrumentation &Controls The licensee is proposing to install one new MDAFW pump at each unit. The pumps will maintain the same start signals as the existing AFW pumps. However, the licensee proposes several changes to the instrumentation and control design basis for the AFW system.

The licensee proposes installation of a low suction line pressure switch and associated timing circuitry to automatically swap the suction of the AFW pumps from the normally aligned CST to safety-related SW system. In addition, the swap over circuitry will contain a trip of the AFW pump if the suction pressure is not re-established within a specific time once auto-transfer is initiated. The NRC staff reviewed the proposed TS Table 3.3.2-1, Function 6.e, associated with the AFW pump suction transfer on low pressure. The NRC staff finds that the setpoint methodology performed by the licensee to be acceptable, as discussed below. The staff also reviewed the SR and found it to conform to SRs for other comparable channels and, therefore, to be acceptable.

As previously discussed, the licensee proposes to add new Function 6.e., "AFW Pump Suction Transfer on Suction Pressure - Low," to Table 3.3.2-1. The licensee performed the setpoint calculation in conformance to setpoint calculation methodology performed for other instrument channels addressed above and the staff finds setpoint calculation methodology for this instrumentation acceptable.

Addition of footnotes (f) to Table 3.3.2-1, SR 3.3.2.3 and SR 3.3.2.8, for Function 6.e addresses how to deal with as-left and as-found tolerances around Nominal Trip Setpoint (NTSP) in conformance with TSTF-493:

Footnote (f) reads: Table 3.3.2-1, Notes 1 and 2 are applicable Note 1 in Table 3.3.2-1 reads: If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

Note 2 in Table 3.3.2-1 reads: The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided

- 26 that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in FSAR Section 7.2.

The addition of a new column, "NOMINAL TRIP SETPOINT" to TS Table 3.3.1-1, Reactor Protection System Instrumentation and Table 3.3.2-1, Engineered Safety Feature Actuation System Instrumentation, and the addition of footnotes (f) to Table 3.3.2-1 and (m) to Table 3.3.1-1 for SR in "Allowable Value" column to address how to deal with as-left and as-found tolerances around NTSP in conformance with TSTF-493, will be incorporated in the PBNP TSs following extended power uprate implementation for each unit.

3.3.6 Human Factors PBNP is equipped with a common control room for the two units. The control room is continuously occupied under all operating and accident conditions, except for a control room fire. The licensee proposes a modification to both Unit's AFW systems, to include new controls, indications, and alarms on both the bench board and vertical boards. The licensee proposes to implement the changes to operator interfaces for control room controls, displays, setpoints, and alarms in accordance with approved plant procedures and processes using DG-G01, Human Factors Design Document. The DG-G01 procedure is based on NUREG-0700, Guidelines for Control Room Design Reviews, and incorporates guidelines specific to PBNP.

The proposed modification installs an automatic swap-over of the AFW suction supply based on low pump suction pressure in order to eliminate the required operator action to manually swap-over the AFW pump suction supply, normally aligned to the CST source, to the safety-related SW system. However, the proposed modification will still require operator actions. In the event of a faulted SG, operators will still be required to isolate the faulted SG.

Although operator action is required to isolate the AFW lines to a faulted SG following a MSlB, the addition of FCVs on the individual MDAFW pump SG discharge headers automatically decreases the maximum flow to the faulted SG while increasing the flow to the non-faulted SG relative to the current system configuration. The new system will maintain flow approximately split between the two SGs regardless of SG pressure. Also, if IA is lost and the backup safety related pneumatic supply is depleted, then operators will be required to manually throttle the minimum recirculation valve and the discharge FCV consistent with the decay heat requirements. In the event a control room fire forces the evacuation of the control room, operators will use of the alternate shutdown capability located outside the control room. These operator actions are similar to the existing system requirements.

The proposed unitized configuration, revised flow control, and automatic switchover modifications enhance the system capability to deliver the required AFW flow during plant transients with no immediate operator actions. Operator action is currently required to balance the MDAFW flow between units. The action is eliminated with the proposed unitized configuration.

The staff requested that the licensee indicate if the new MDAFW pumps will have local control stations and if the air-operated valves will have manual capability. The licensee responded that operators will maintain the same remote, manual capabilities with the new MDAFW pump and valves as the currently installed AFW system.

- 27 Procedures and Training Procedure changes are required to support the AFW system modification due to the system being modified from a shared system to a unitized system. The changes to emergency and abnormal operating procedures (EOPs and AOPs) as a result of the AFW modifications do not significantly impact operator actions or mitigation strategies. The licensee stated that the changes will be reflected in revised procedures and that operators will receive classroom and simulator training prior to implementation.

Changes to Operator Actions The licensee identified the following changes:

Eliminate the operator time required for AFW pump suction supply swapover from the normal CST suction source to the safety-related SW suction source, which will be an automatic swapover function based on low-low AFW pump suction pressure Eliminate the operator action time required to manually align shared AFW pumps to the affected unit Operator action times available after a SGTR remain unchanged The licensee stated that these actions, and any new operator actions or changes in current operator actions that may be identified during the design process, will be addressed in accordance with plant procedure FP-OP-CTC-O.1, "Control of Time Critical Operator Actions,"

and the list of time critical operator actions listed in Attachment E of OM 4.3.2, "EOP/AOP VerificationNalidation Process," will be revised. The changes will be appropriately proceduralized and the operators will receive formal classroom and simulator training for their implementation as required by the Systematic Approach to Training Process outlined in FP-SAT-60, "Systematic Approach to Training (SAT) Process Overview."

Changes to Control Room Controls, Displays and Alarms The licensee stated that any newly installed instruments or components required to support the AFW modification will be implemented in accordance with approved plant procedures and processes. DG-G01, "Human Factors Design Document," provides the necessary guidance such that control room modifications will continue to conform to the human factors criteria established during the Control Room Design Review Project performed at PBNP. The DG-G01 procedure is based on NUREG-0700, "Guidelines for Control Room Design Reviews," and incorporates guidelines specific to PBNP. The licensee stated that this modification will implement changes to the control room to modify both existing and new controls and displays.

Also, significant circuit changes will be made for both the existing and new control circuits for the AFW pumps, valves and instrumentation. Specific details for these changes will be identified and addressed during the development of the AFW system modification.

Conclusion The NRC staff finds that the licensee has adequately addressed the human performance aspects of the proposed AFW modification. The licensee's current plant modification control processes will be used to identify needed changes to procedures, training, human interfaces in the control room and alternate shutdown facility (including the Safety Parameter Display

- 28 System). The current processes will also ensure that the overall effectiveness of the modification and the supporting displays, controls, procedures, and training are verified and validated prior to implementation. In general, the proposed modification will reduce operator workload and is, therefore, acceptable for implementation.

3.3.7 Environmental Qualification (EQ) of Electrical Components The proposed modification will install new and relocated AFW equipment that must meet the EQ design basis. In response to the NRC staff's questions regarding the AFW modifications on PSNP EQ, the licensee stated in its response dated March 3, 2010, that the normal radiation level is 1300 RAD for 60-year total integrated dose, and the AFW pumps and associated equipment will not be included in the EQ program since they are not credited in the accident analysis although they are sequenced loads used in a loss-of-coolant accident (LOCA). In addition, the licensee stated that the AFW pumps are connected to safety-related buses through safety-related breakers. The breakers will prevent degraded MDAWF pump motors from adversely affecting the safety-related bus during the accident.

The NRC staff was concerned regarding the failure modes and its effects on the equipment needed to perform safety functions including potential for presenting misleading information to the operator during and after an accident. Therefore, the staff requested the licensee describe the failure modes and effects analysis performed to show that there are no adverse effects for not qualifying the AFW pump motors. In its response dated August 9, 2010, the licensee stated that the MDAFW pump safety-related breakers serve as an isolation device to prevent failures of the MDAFW pump motors from adversely affecting safety-related accident mitigation functions being powered from the bus. Protection of the new MDAFW pumps against motor overload is provided via protective relays installed in their respective 4160 V switchgear. Each switchgear breaker includes instantaneous and inverse time overcurrent protection, as well as ground fault protection.

The licensee evaluated the electrical protection afforded for the new MDAFW pumps. The results of the calculation show that the motors and power supply cables are protected against both overload and short circuit, and that the MDAFW pump breakers properly coordinate with their upstream breakers. In addition, the licensee stated that during a large break LOCA, the AFW pumps are secured early in the accident since steam generator levels are rapidly restored and the AFW pumps are not needed for the large break LOCA response. Therefore, there is no significant radiation dose accumulation in the new MDAFW pump rooms, when the pumps are running, that would cause a motor failure. For small break LOCA, steam generator tube rupture, MSLS, loss of normal feedwater and loss of AC events, there is no harsh environment in the MDAFW pump rooms.

Since the AFW pumps are in a mild environment for these events that require their operation, harsh environment qualification is not needed. The staff finds the licensee's response acceptable.

3.3.8 Heating Ventilation and Air Conditioning The new, MDAFW pumps and their 350 Hp motors will each be located in separate rooms in the 8' elevation of the PAS. These rooms have a large opening to the general area of the PAS, which contains safety-related instrumentation and safety-related pumps. The general area of the PAB is cooled by the Primary Auxiliary Building Ventilation System (VNPAB). The VNPAB

- 29 is a non-safety related system. However, in the current licensing basis, the system takes credit for providing sufficient control of building temperatures during accident conditions to maintain equipment within operational temperature limits. In a letter dated October 15, 2010, the licensee clarified the operation of the VNPAB during accident conditions as follows:

NextEra performed a pre-EPU evaluation, results of which shows that placing the VNPAB in service within approximately two hours of the worst-case DBA with a loss of offsite power (LOOP), assures functionality of the post-accident monitoring instrumentation contained in the PAB. In the current licensing basis, procedures direct that equipment be restored following DBAs with LOOP. These procedures permit the operators to manually restore loads that are stripped following an SI in accordance with the EDG load management guidance and plant conditions. The two hours stipulated in the capability evaluation has not been formalized as such into plant procedures at the present time because it was used in the evaluation as a minimum gross capability and not as a design limit. The existing procedural instructions are being revised in accordance with the provisions of the corrective action program and the 10 CFR 50.59 process. NextEra will validate the requirement to restore VNPAB prior to implementation of the revised operating procedures and training associated with the installation of the new AFW system.

The new MDAFW pumps have a shaft mounted fan that eliminates the need for an external fluid to provide shaft or seal cooling. The additional heat due to this arrangement and the pump motor heat will add to the overall PAB heat load. The rooms in which the new MDAFW pumps will be located are equipped with a return air register to pull air into the room from the general area of the PAB. In a letter dated October 15, 2010, the licensee stated that restoration of the VNPAB within two hours assures adequate cooling for PAB safety-related equipment, including the additional heat load from operation of the new MDAFW pumps. Further, in a letter dated November 12, 2010, the licensee proposed the following regulatory commitment:

Validation of the time requirement to restore Primary Auxiliary Building Ventilation (VNPAB) will be completed as part of implementation of the revised operating procedures and training associated with the installation of the new Auxiliary Feedwater (AFW) system no later than the Unit 2 (2011) refueling outage.

The currently installed MDAFW pumps and the TDAFW pumps are served by the Control Building AFW Pump Area Ventilation System (VNAFW). The current MDAFW pumps will be re-designated as SSGs and will no longer be credited for SG cooling in any of revised accident or transient analyses. However, the TDAFW pumps will still be required for accident analysis.

Therefore, the ventilation design basis heat load during anticipated modes of AFW operation for VNAFW will be reduced. The NRC staff finds the licensee's conclusion that the TDAFW pump room will remain bounded by the current analysis for the VNAFW acceptable.

3.4 Design Basis Accidents AFW is credited in the mitigation of the following design basis accidents:

Loss of Non-Emergency AC Power to the Station Auxiliaries (LOAC)

Loss of Normal Feedwater Flow (LONF)

Steam Generator Tube Rupture (SGTR)

Secondary System Pipe Ruptures

- 30 Anticipated Transients Without Scram (A TWS)

Small break Loss of coolant accident (SBLOCA)

For the purposes of this safety evaluation, the NRC staff evaluated modifications to the AFW system against the safety functions credited in the current licensing basis at the current power level, not at the proposed EPU power level.

3.4.1 Loss of Normal Feedwater and Loss of Alternating Current Loss of MFW flow results in an increase in RCS temperature and pressure that eventually requires a reactor trip to prevent fuel damage. Decay heat must be transferred out of the fuel to the RCS to the secondary system. If an alternative supply of feedwater is not supplied, then the core residual heat would heat the RCS water to the point where water relief from the pressurizer could occur, resulting in a substantial loss of water, fuel uncovery, and potential fuel damage.

The FSAR describes the most limiting AFW transient is a LONF event, without a concurrent LOAC, where the fuel continues to add heat to the RCS at 100 percent power until a low-low SG level reactor trip occurs. A LONF event could occur from pump failures, valve malfunctions, or a loss of offsite power (LOOP). Both the LONF and the LOAC events are time-sensitive to AFW system start-up; and both events also require a minimum AFW flow to ensure the safety function is met. To meet the current design conditions specified in the licensee FSAR to mitigate a LONF accident, the AFW system must automatically start and deliver adequate flow within five (5) minutes after the initiating signal (low-low SG trip). Additionally, assuming a limiting single failure of one AFW pump, the AFW system must provide a minimum of 200 gpm of flow under the CLB, which can be supplied to one SG or split between the two SGs. These AFW design requirements ensures that the water level in the SGs does not recede below the lowest level at which sufficient heat transfer area is available to dissipate core residual heat.

The licensee states that with the new MDAFW pumps, AFW flow will be initiated 60 seconds after the low-low SG water level setpoint is reached, and 100 percent flow, minimum of 275 gpm, will be obtained within 150 seconds to one or split equally between two SGs.

Therefore, the licensee concludes the new AFW system design will meet the design bases requirement to mitigate a LONF and LOAC event by providing sufficient supply of water in the required time to dissipate the core residual heat without the pressurizer reaching a water solid condition.

The NRC staff finds the proposed AFW modification acceptable with respect to the LONF event, because the licensee provided information to demonstrate that the modified AFW system will remain capable of meeting the assumptions used in the licensing basis safety analysis for the LOl\\IF event, as described above and in Point Beach UFSAR Section 14.1.10.

3.4.2 Steam Generator Tube Rupture In a SGTR, it is important to limit the supply of feedwater to the faulted SG while maintaining adequate flow to the intact SG in order to properly mitigate the consequences of the event. The licensee's proposes to add FCVs on the new MDAFW pump discharge headers to each SG.

The new FCV setpoints will be set to initially provide each SG with approximately one-half of that unit's MDAFW pump flow. Hence, the flow control valves will automatically limit the flow initially to the ruptured SG and provide a throttled flow to the intact SG. Operator action will still

- 31 be required to isolate the AFW flow to a ruptured SG following a SGTR event to minimize the potential for SG overfill.

During a SGTR, the licensee's current licensing basis requires that adequate AFW flow be delivered to the intact SG in order to cooldown the RCS to gain adequate subcooling margin.

Once adequate subcooling is obtained, operators can begin depressurizing the RCS to stop RCS flow out the ruptured tube into the main steam system; thereby, avoiding an SG overfill and limiting the potential release of radioactive material to the environment. Therefore, the AFW system is required to automatically start and deliver a sufficient, but limited amount, of feedwater flow to maintain adequate SG levels during a SGTR.

The licensee states that with the new MDAFW pumps, AFW flow will be initiated 60 seconds after the low-low SG water level setpoint is reached. Full AFW l:low (I.e., 100 percent flow) at a minimum of 275 gpm will be obtained within 150 seconds to one SG, or split equally between two SGs. For a SGTR event, operator action is required to isolate AFW to the ruptured SG once SG level has recovered and provide AFW flow to the intact SG to effect a rapid RCS cooldown.

The licensing basis radiological consequences analyses for the steam generator tube rupture event credit a manual action to secure AFW flow, an action which is assumed to occur on the order of six minutes. Because the increased AFW flow to the ruptured steam generator would be over a period of six minutes, the NRC staff believes that this would result in the addition of an insignificant amount of liquid to the ruptured steam generator. This would have a minimal impact on the radiological consequences of the evaluated accident. On this basis, the NRC staff finds the proposed AFW system modification acceptable at currently licensed thermal power conditions with respect to the radiological consequences of a postulated steam generator tube rupture at PBNP.

3.4.3 Main Steam Line Break In a MSLB event, it is important to limit the supply of feedwater to the faulted SG in order to mitigate the consequences of an excessive RCS cooldown, and provide sufficient AFW flow to the intact SG to prevent the RCS from heating back up after the faulted SG has blown down.

The licensee's proposes to install FCVs on the new MDAFW pump discharge headers to each SG. These flow control valves will automatically limit the AFW flow to the faulted SG, thereby, limiting the resulting RCS cooldown. However, operator action will still be required to isolate the AFW flow to a faulted SG, as is the case in the current licensing basis..

For a MSLB, the AFW flow to the faulted SG will flash to steam and exit through a break inside containment. The AFW flow compounds the accident by adding to the energy released inside containment, through the steam line break, challenging the containment integrity, and the AFW flow continues to cooldown the RCS adding positive reactivity. In order to bound the accident, the licensee calculations assume MFW and AFW pumps are operating at full capacity when the break occurs. The licensee assumes a conservatively high AFW flow rate of 1200 gpm at a minimum temperature of 35°F is delivered to the affected SG. Even though MFW is assumed to be isolated following the SI signal, AFW is assumed to continue for the duration of the transient.

The licensee's containment analysis models the AFW flow to the SGs, and credits some containment heat removal through the non-faulted SG.

- 32 The AFW system is required to automatically start and deliver a sufficient, but limited amount, of feedwater flow to maintain adequate SG levels during a MSLB event. Minimum AFW flow rates are not currently described in the CLB for a MSLB, but adequate AFW flow is assumed to be available. The new MDAFW pump discharge lines will have one FCV per SG, initially set to deliver an equal amount of AFW to each SG, which will limit the flow to a faulted SG. Therefore, the licensee concludes the new AFW system design provides sufficient, but limited, feedwater flow in the required time to dissipate the core residual heat from the RCS, to prevent a subsequent RCS heatup.

In a letter dated April 22, 2010, the licensee stated that the current analyses remains applicable or is unaffected by implementation of the new AFW system and associated TS changes, with the exception of the MSLB containment response and steam generator tube rupture (SGTR) radiological consequences. The license further stated that these accidents were reanalyzed with the current licensing basis for the AFW modifications and the results are acceptable with the revised minimum and maximum flow rates and pump start times. In response to an NRC staff RAI, the licensee further clarified by letter dated November 12, 2010, that all codes used in the analyses including assumptions, AFW pump start times, and single failures remained the same between the MSLB analysis addressing the implementation of the proposed AFW system modifications and the CLB MSLB analysis. The AFW pumps were assumed to start conservatively early at the time of the SI signal, consistent with the CLB. The only input change made was to the AFW flows which led to changes in two transient-dependent boundary conditions, the containment back pressure and MFW flow rates. A more accurate adjustment of the transient-dependent conditions than in the current analysis resulted in a net benefit in the results of the modified analysis for implementation of the new AFW system. The licensee stated that the peak containment pressure in the current analysis (prior to AFW modifications) is 59.85 psig occurring at 281 seconds. After the AFW modification installation, but prior to EPU implementation, the peak containment pressure is 59.58 psig occurring at 277 seconds. The respective peak containment temperatures are 284.9°F and 285°F.

The licensee stated that the MSLB analysis for determining containment pressure and temperature during post AFW modifications, but prior to EPU implementation, is consistent with the current analysis. A review of the current MSLB analysis in the PBNP FSAR indicates that appropriate inputs were used to maximize the containment pressure and temperature. The containment design pressure and temperatures are 60 psig and 286°F, respectively. The calculated pressure and temperatures, albeit close to design as in the current analysis, still remain slightly lower than design. GDCs 16 and 50 are satisfied since the proposed AFW modifications would not result in pressures and temperatures exceeding the containment design limits.

3.4.4 Small Break Loss-of-Coolant Accident During a SBLOCA, the licensee's CLB in the FSAR does not credit the AFW system for any immediate short-term transient mitigation. The licensee analyzed the SBLOCA event without AFW to be conservative and to limit the modeling required to address all possible combinations and time-delays of AFW system configurations. The licensee does credit the AFW system if available during the plant recovery and cool down phase following the SBLOCA. AFW is used in the cooldown of the RCS, which reduces the RCS pressure, thereby, reducing the RCS leakage and allows for increased charging flow. Although, the AFW system may be initiated during the SBLOCA, the event has been analyzed with no credit for AFW.

- 33 The MOAFW and TOAFW pumps are currently designed to automatically start on an SI signal.

The licensee's proposed AFW modification will also include the same start signal to the new MOAFW pump upon an SI signal. The licensee concludes that even though the new MOAFW pump has a larger flow capacity, the current analysis which assumes no AFW flow bounds the proposed new MOAFW pump for a SBLOCA.

The licensee does not credit the AFW system in the SBLOCA analyses. Assuming no AFW flow is conservative with respect to the SBLOCA analyses. Therefore, the NRC staff finds the proposed AFW modification acceptable with respect to the SBLOCA analysis. The results of the SBLOCA analyses are unaffected by the proposed modification.

3.4.5 Secondary System Pipe Ruptures Feedwater system pipe breaks inside and outside containment pipe break could cause excessive RCS cooldown by energy discharge through the break similar to a MSLB event. A feedwater line break could also result in RCS heatup by reducing feedwater flow to the affected RCS similar to LONF event.

The licensee states that the feedwater system pipe breaks are not required to be analyzed per the PBNP current licensing basis. In FSAR Section 1.3, the licensee states that the GOC used during the licensing of PBNP predates those provided today in 10 CFR 50, Appendix A. The PBNP GOC originated from the Atomic Energy Commission proposed GOC. The PBNP equivalent GOC for 10 CFR 50, Appendix A, GOC 27,28,31 and 35 are as follows: (PBNP GOC 30) FSAR Section 3.1.2.6, (PBNP GOC 32) FSAR Section 3.1.2.8, (PBNP GOC 33) FSAR Section 4.1, (PBNP GOC 44) FSAR Section 6.2.

The proposed modifications to the AFW system have two key impacts on the secondary system pipe rupture analysis: 1) the total AFW flow rates are higher than the current analysis, and 2) there is now a different AFW system single failure to be considered that can increase the maximum AFW flow rate.

Generally, within the first minute following a steam line break, the AFW system is initiated on any one of several protection system signals. AFW to the faulted steam generator will increase the secondary mass available for release to containment. Maximum AFW flow rates from both the MOAFW pump as well as the TOAFW pump are assumed. The AFW flow initiation is assumed to start at the time an SI setpoint is reached, with no electronic or pump start-up delay.

Operator action is credited to terminate AFW flow to the faulted steam generator 10 minutes after the initiation of the steam line break.

There are three single failures that are analyzed for this event: an AFW runout protection failure, a feedwater isolation valve failure, and a failure of a safeguards train.

The limiting single failure in the AFW system results in a maximum delivery of AFW to the faulted SG. At PBNP, the most limiting AFW single failure is a FCV failed open on the faulted SG. The additional AFW delivered to the faulted SG will result in increased mass and energy releases inside containment.

In the November 30, 2010, letter, the licensee stated that the hot zero power main steamline break analyses, for both the current licensing basis and to support the EPU, conservatively models AFW flow in order to maximize the asymmetric cooldown of the RCS. Specifically, the analyses assume a maximum AFW flow rate of 1200 gpm to the faulted SG. The delivery of

- 34 AFW is assumed to begin at the start of the transient. The licensee also stated that both the present and proposed AFW system configurations have been confirmed to remain bounded by the assumptions used in the analyses.

The licensee reviewed the mass and energy release assessment for the postulated secondary system pipe ruptures with the limiting single failure of the AFW FCV. Based on its review, the licensee concludes that the analysis meets the PBNP CLB requirements with respect to PBNP GDC 10 for ensuring that the analysis is conservative (Le., that the analysis includes sufficient margin). Therefore, the licensee concludes that the proposed AFW modification is acceptable with respect to mass and energy release for postulated secondary system pipe ruptures.

The NRC staff finds the proposed AFW modifications acceptable with respect to the main steam line break accident because the modified system capability remains bounded by the current licensing basis analysis with respect to postulated secondary system pipe ruptures.

3.5 Beyond Design Basis Accidents 3.5.1 Plant Fires and Appendix R Fire Scenarios The licensee states that the proposed modification to the AFW system will improve their capability to meet the separation requirements specified in 10 CFR 50 Appendix R. The new MDAFW pumps will be located in separate fire areas than the existing TDAFW pumps. The licensee will route power and control cables, and locate selected motor control centers, to ensure adequate separation of the TDAFW and MDAFW pump systems. The licensee stated that compliance with 10 CFR 50 Appendix R separation and protection requirements is confirmed as part of the modification process. Since the modifications resulted in redundant trains in the same fire areas, the licensee provided information by letter dated June 17, 2009, identifying the fire areas in the plant where the trains of conduit and required control cables would be protected by a three hour fire barrier or by rerouting required circuits to meet Appendix R separation requirements. This meets the requirements of 10 CFR 50, Appendix R.

In the FSAR, the licensee states that in the event of a plant fire the AFW system shall be capable of manual initiation to provide feedwater to a minimum of one SG per unit at sufficient flow and pressure to remove decay and sensible heat from the RCS over the range from hot shutdown to achieve cold shutdown conditions within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Additionally, indications and controls shall be provided outside the control room, so plant operators can shut down and maintain the plant in a safe condition.

The licensee states that both the MDAFW and TDAFW pumps will have local control stations located at each of the pumps, such that AFW can be supplied to the SGs. Therefore, the AFW modification ensures that either AFW pump system can supply the required AFW flow from outside the control room. The NRC finds this acceptable with respect to plant fires and Appendix R scenarios.

3.5.2 Protection Against Missiles and High Energy Line Breaks The modification proposes to install a new MDAFW pump system in a different location in the auxiliary building than the existing AFW system components. The NRC staff asked the licensee if there were any high energy (HE) lines that could potentially affect the new MDAFW pumps.

The licensee responded that based upon their definition of HE lines in their CLB, no HE lines

- 35 were located in the vicinity of the new MDAFW pumps that could adversely affect their function, The licensee states that their definition of a HE line is one containing a fluid that is both greater than 200°F and greater than 275 psig. Therefore, the licensee does not classify low pressure heating steam lines in the auxiliary building as HE lines. By definition, the licensee does not consider the new AFW system a HE line. Therefore, the licensee's evaluation of the proposed modification of the AFW system concluded that the proposed modifications do not affect the current HE line analysis.

The licensee states that the proposed modifications for all SSCs are protected from internally generated missiles. Additionally, the licensee has evaluated non-safety related SSCs in the vicinity of safety-related SSCs to ensure the intended safety function of the safety-related SSC will not be affected by a failure of the non-safety related SSCs. The licensee's review of plant areas outside containment containing safety-related SSCs revealed the proposed modification will not change existing missile sources.

In reference to Pipe Rupture Locations and Associated Dynamic Effects, the licensee indicated in its RAI response that according to the CLB definition for HE lines presented in the PBNP FSAR, Appendix A.2, the AFW pump suction and discharge lines are not HE lines. Accordingly, the licensee had not performed high energy line break (HELB) analyses for the AFW pump suction and discharge lines. The NRC staff finds this acceptable because this is consistent with the licensee's CLB that the licensee has stated in its staffs RAI response, The only lines in the AFW system that are HE lines in accordance with the PBNP CLB include the steam supply lines for the TDAFW pumps, which are normally pressurized from the main steam (MS) system up to the normally closed TDAFW pump steam supply motor-operated valves (MOVs). These pressurized lines are considered HE lines. The licensee also indicated in letter dated October 15, 2010, that the design of these steam supply lines is not affected by the AFW system modification or by the PBNP HELB reconstitution (currently identified in UFSAR 2007, Appendix A.2). The licensee also stated in this letter that the "existing design of the HE steam supply piping up to the normally closed TDAFW pump steam supply valves has been evaluated for HELB and meets the current HELB licensing basis." The licensee also indicated in letters dated October 1 and October 15, 2010, that the HELB evaluations at EPU conditions did not identify any new break locations for these AFW steam supply piping. The staff notes that following the submittals of these letters, in communications with the licensee, the staff was made aware that the licensee had changed its proposed methodology for HELB reconstitution and reevaluated the HE systems with a new methodology and criteria which the staff has found acceptable. Due to these changes in HELB criteria and methodology, the licensee identified additional breaks in the AFW steam supply lines at locations near the terminal ends of these lines, where breaks were previously identified as terminal end breaks. In letter dated December 21,2010, the licensee concluded that these newly identified breaks have no adverse impact on essential equipment. The NRC staff also notes (and the licensee has concurred on a teleconference on January 13, 2011) that the AFW HE steam supply lines meet the current HELB licensing basis without requiring postulation of the newly found breaks and that the AFW steam supply piping is not affected by the AFW system modification. Based on the above, the staff finds that the licensee has provided reasonable assurance that the AFW system with its proposed modifications will continue to function in accordance with the station's current licensing basis.

Based on the licensee's responses, the staff has concluded that the upgraded AFW system is not affected by the station's HELB reconstitution. In addition, the NRC staff finds that the licensee has provided reasonable assurance that the HE AFW steam supply lines will continue

- 36 to function in accordance with the station's current HELB licensing basis. The NRC staff, therefore, finds the AFW modification acceptable with respect to missiles and HELB.

3.5.3 Anticipated Transient without Scram In accordance with 10 CFR 50.62, a licensee is required to have provisions for automatic initiation of the AFW system in the event of an Anticipated Transient without Scram (A TWS).

The AFW system must be capable of automatic actuation by use of equipment that is diverse from the reactor trip system.

In FSAR Section 7.4, the licensee states that the ATWS Mitigating System Actuation Circuit (AM SAC) trips the main turbine and starts both the shared MDAFW pumps and the unit specific TDAFW pump on loss of MFW when the main turbine is above 40 percent nominal power. The licensee's proposed modification will maintain the current design that both the TDAFW and MDAFW pumps systems will automatically start on an AMSAC signal after a gO-second time delay.

The increased capacity of the proposed, modified AFW system would have no effect on the PBNP A TWS safety analysis. Therefore, the NRC staff finds the AFW system modification acceptable with respect to an A TWS event.

3.5.4 Station Blackout In accordance with 10 CFR 50.63, a licensee must be able to withstand and recover from a SBa event. In Appendix A.1 of the FSAR, the licensee states that the AFW system is capable of automatically supplying sufficient feedwater to remove decay heat from both units without any reliance on alternating current (AC) power for one hour. In order to support this function, the licensee must maintain an adequate quantity of water in the CST, ensure sufficient capacity in the safety-related batteries, and ensure the temperature in the AFW pump room does not exceed maximum for equipment reliability.

The licensee does not credit the use of the MDAFW pump for mitigating a SBa event; only the TDAFW pump. Therefore, the proposed new MDAFW pump will not impact the SBa analysis.

However, as part of the proposed modification, the licensee will modify the DC power supply associated with components required for operation of the TDAFW pumps to be all on the same DC train. Refer to electrical section of the SER for discussion of the DC bus changes.

In response to the staff's questions regarding the AFW modifications on PBNP SBa mitigation strategy and commitments, the licensee confirmed that AFW System upgrades will not change the existing SBa coping duration, loading on the alternate AC source, coping methodology, or SBa mitigation strategy. Therefore, the staff finds the licensee's response acceptable.

Based on the licensee's responses, the staff has concluded that the upgraded AFW system will continue to provide reasonable assurance of safety during a SBa event. The NRC staff finds the AFW modification acceptable with respect to withstanding and recovering from a SBa event.

3.6 Technical Specifications The design basis for the AFW system is to supply high-pressure feedwater to the steam generators in order to maintain a water inventory for removal of heat energy from the reactor coolant system by secondary side steam release in the event of inoperability or unavailability of the main feedwater system.

Section 182a of the Atomic Energy Act (the Act) requires applicants for nuclear power plant operating licenses to include TSs as part of the license. The TSs ensure the operational capability of structures, systems and components that are required to protect the health and safety of the public.

The NRC's requirements related to the content of the TSs are set forth in 10 CFR 50.36, "Technical specifications." This regulation requires that the TSs include items in five specific categories. These categories include: (1) safety limits, limiting safety system settings and limiting control settings (50.36(c)(1)); (2) limiting conditions for operation (LCOs) (50. 36(c)(2));

(3) surveillance requirements (SRs) (50.36(c)(3>>; (4) design features (50.36(c)(4>>; and (5) administrative controls (50.36(c)(5>>.

Section 50.36( d)(2)(ii) of 10 CFR states that a TS LCO must be established for each item meeting one or more of the following criteria:

Criterion 1: Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary.

Criterion 2: A process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of, or presents a challenge to the integrity of a fission product barrier.

Criterion 3: A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of, or presents a challenge to the integrity of a fission product barrier.

Criterion 4: A structure, system, or component which operating experience or probabilistic risk assessment has shown to be significant to public health and safety.

Section 50.36(d)(1 )(ii)(A) of 10 CFR states, 'Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded."

Furthermore, Section 50.36(d)(3) states, "Surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions of operation wilt be met."

In general, there are two classes of changes to TSs: (1) changes needed to reflect modifications to the design basis (TSs are derived from the design basis), and (2) voluntary changes to take advantage of the evolution in policy and guidance as to the required content and preferred format of TS over time. This amendment deals with the first class of changes. In determining the acceptability of revising TS 3.7.5, "Auxiliary Feedwater System," the NRC staff used the accumulation of generically approved guidance in NUREG-1431, Revision 3,

- 38 "Standard Technical Specifications, Westinghouse Plants," dated June, 2004, as modified by Technical Specification Task Force (TSTF)-412, Revision 3, "Provide Actions for One Steam Supply to Turbine Driven AFW/EFW Pump Inoperable," (TSTF-412).

The following TS changes were proposed by the licensee:

TS 3.3.2, ESFAS Instrumentation, Table 3.3.2-1, Function 6.e SR 3.3.4.3, Loss of Voltage Time Delay Channel Calibrations TS 3.7.5, Auxiliary Feedwater (AFW)

TS 3.7.6, Condensate Storage Tank (CST)

SR 3.8.1.7, EDG Load Testing TS 3.3.2, ESFAS Instrumentation, Table 3.3.2-1, Function S.e The licensee added new Function 6.e., "AFW Pump Suction Transfer on Suction Pressure Low," to Table 3.3.2-1. The licensee performed the setpoint calculation to conform with the setpoint calculation methodology described in TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions." The NRC staff finds setpoint calculation methodology for this instrument to be acceptable, as discussed below.

Addition of footnotes (f) to Table 3.3.2-1, SR 3.3.2.3 and SR 3.3.2.8, for Function 6.e addresses how to deal with as-left and as-found tolerances around Nominal Trip Setpoint (NTSP) in conformance with TSTF-493:

Footnote (f) reads: Table 3.3.2-1, Notes 1 and 2 are applicable Note 1 in Table 3.3.2-1 reads: If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

Note 2 in Table 3.3.2-1 reads: The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in FSAR Section 7.2.

The addition of a new column, "NOMINAL TRIP SETPOINT" to TS Table 3.3.1-1, Reactor Protection System Instrumentation and Table 3.3.2-1, Engineered Safety Feature Actuation System Instrumentation, and the addition of footnotes (f) to Table 3.3.2-1 and (m) to Table 3.3.1-1 for SR in "Allowable Value" column to address how to deal with as-left and as found tolerances around NTSP in conformance with TSTF-493, will be incorporated in the PBNP TSs following extended power uprate implementation for each unit.

As discussed in Section 3.3.1, the NRC staff reviewed the proposed design and finds that the proposed automatic swap-over from CST to SW supply for the suction to the AFW pumps will satisfy the assumptions in the current licensing basis for AFW flow, and will adequately protect

- 39 the AFW pumps from damage if suction pressure is lost. Therefore, the NRC staff finds the proposed TS to be acceptable under current licensed power conditions.

SR 3.3.4.3, Loss of Voltage Time Delay Channel Calibrations The NRC staff in the Electrical Engineering Branch evaluated the loss of voltage (LOV) relay settings for the safety-related 4160 V buses and non-safety related 4160 V buses and determined that the existing LOV relay time delays are not adequate to ride through a grid disturbance at EPU conditions. Technical Specification 3.3.4 "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation" will be revised to incorporate new LOV time delay allowable values for safety-related buses. Specifically, SR 3.3.4.3.a. will be revised from, "with a time delay of;:: 0.7 seconds and :s; 1.0 second," to "with a time delay of;:: 1.8 seconds and

s; 2.3 seconds (Bus Loss of Voltage Relay) and of ~ 1.95 seconds and :s; 3.55 seconds (EDG Breaker Close Delay Relay)" and SR 3.3.4.3.c will be revised from "with a time delay of

s; 0.5 seconds" to "with a time delay of ~ 1.15 seconds and :s; 1.6 seconds."

In response to staff's RAJ related to the impact of increasing the time delay for the LOV relays and EDG breaker closure time on performance of equipment operating under degraded voltage conditions for extended duration and accident analyses, the licensee, in letter dated April 28, 2010, stated that a detailed analyses had been performed for the proposed changes to TS 3.3.4. The licensee concluded that:

The maximum allowable time delay was established to ensure the satisfactory operation of equipment would occur without tripping over-current protective devices when the voltage is below the degraded voltage relay setpoint but above the LOV relay setpoint.

Over-current protective device will not trip as a result of the higher current from the motors operating at just above the LOV relay setting for at least 48 seconds.

The time delay associated with the EDG breaker close delay relay still ensures the time requirements of the PBNP FSAR Chapter 14 accident analyses remain valid.

In the event of voltage conditions below the degraded voltage relay setpoint and no safety injection signal, the equipment is expected to operate as designed and the equipment response time for accident analyses remains valid.

The time delay for the LOV relays is adequate to ride through transient low voltage conditions during EDG loading when responding to an accident signal.

Based on the licensee's responses to the staffs RAI, the NRC staff finds the proposed changes to TS 3.3.4 are acceptable.

TS 3.7.5, Auxiliary Feedwater (AFW)

Proposed changes to TS 3.7.5, "AFW System," reflect the new unit-specific MDAFW pump system design. The changes to TS 3.7.5 are generally consistent with TS 3.7.5, "Auxiliary Feedwater (AFW) System," contained in NUREG-1431, Standard Technical Specifications (STS), Westinghouse Plants, Revision 3, as modified by TSTF-412. Deviations were made due to preferences in terminology and differences in how PBNP is configured, as compared to the configuration assumed in NUREG-1431. The terminology "pump systems" contained in the existing PBNP TSs has been retained, rather than adopting the STS term "train" when referring

- 40 to the new AFW system. The licensee chose to describe its installed systems as "pump systems" versus "trains" since the flow paths associated with the AFW pumps are not associated with a specific engineered safety feature safety train. Use of "pump systems" represents the valves and piping that support the ability of an AFW pump to provide the required accident analysis flow rates. Pump systems more aptly describe the AFW system at two-loop pressurized water reactor plants. The NRC staff's approval for use of this terminology is documented in the safety evaluation approving the PBNP Improved TSs (ADAMS Accession No. ML012250504).

Specified Safety Function of the AFW System The analysis basis for TS 3.7.5 state that the AFW automatically mitigates the consequences of any event with the loss of normal feedwater. The AFW pumps take suction through separate and independent suction headers from the CSTs and pumps to the SG secondary side via one connection on each MFW piping outside containment. The SGs function as a heat sink for core decay heat. The heat load is dissipated by releasing steam to the atmosphere from the SGs via the main steam safety valves or atmospheric dump valves. If the main condenser is available, steam may be released via the steam bypass valves and recirculated to the CST. The AFW system removes decay heat and other residual heat by delivering at least the minimum required flow rate to the steam generators at pressures in excess of the SG safety valve set pressure. In addition, the AFW system must supply enough makeup water to replace steam generator secondary inventory lost as the unit cools to Mode 4 conditions.

The AFW system is assumed to function in the mitigation of design-basis accidents (DBAs) and transients that include the following: SGTR, MSLB, loss of normal feedwater, and loss of all AC power to the station auxiliaries. The AFW system must be capable of isolating AFW to the ruptured steam generator following a SGTR in addition to isolating the steam supply to TDAFW pump associated with the ruptured SG. Although the AFW system will be initiated during the SBLOCA, the event has been analyzed with no credit for AFW. The SBLOCA was analyzed without AFW to be conservative and to limit the modeling required to address all possible combinations and time delays for various AFW system configurations.

The Engineered Safety Feature Actuation System automatically actuates the AFW pumps and associated power operated valves and controls when required to ensure an adequate feedwater supply to the steam generators.

Changes to TS 3.7.5 Limiting Conditions for Operation (LCOs)

LCO 3.7.5

Replace "The AFW System shall be OPERABLE with; one turbine driven AFW pump system and two motor driven AFW pump systems." with; "The AFW System shall be OPERABLE with; one turbine driven AFW pump system and one motor driven AFW pump system."

LCO 3.7.5 is revised to require that the AFW system shall be OPERABLE with one TDAFW pump system and one MDAFW pump system. In addition, the LCO Note to TS 3.7.5 pertaining to the MDAFW pump system operability requirements in Mode 4 is revised to make changes

- 41 consistent with the unitized MDAFW pump design by deleting the language that the Mode 4 MDAFW is the MDAFW pump associated with SG relied on for heat removal.

The purpose of LCO 3.7.5 is to establish requirements for the lowest functional levels or performance capability of AFW System equipment to ensure the AFW pumps systems will perform their specified safety function to mitigate the consequences of any event with the loss of normal feedwater. Current TS 3.7.5 requires one TDAFW pump system and two MDAFW pump systems to be operable. PBNP Units 1 and 2 designs are being modified to include a unitized full-capacity MDAFW pump system replacing part-capacity shared MDAFW pump system.

Each full-capacity MDAFW and full-capacity TDAFW pump system will automatically start and deliver adequate flow to maintain SG levels during antiCipated transients that result in a loss of the main feedwater system. As a result of the modification, the AFW system for each unit will consist of one full-capacity MDAFW pump system and one full-capacity TDAFW pump system.

The NRC staff has accepted the modification of the AFW system to include a unitized full capacity MDAFW pump system in Section 3.3 of this Safety Evaluation. The NRC staff finds that the proposed LCO changes to AFW system operability requirements and the changes to the LCO Note are based on approved analyses and evaluations of the design and will ensure the AFW system has the functional capability to mitigate the consequences of any event with loss of normal feedwater. Therefore, the NRC staff concludes that the proposed changes comply with 10 CFR 50.36 and are acceptable.

Changes to TS 3.7.5 ACTIONS Requirements LCO 3.7.5 ACTIONS are revised to make changes to remedial actions permitted by TSs based on the modified AFW system design for unitized full-capacity MDAFW pump systems. The TSs are developed to preserve the single failure criterion for systems that are relied upon in the safety analysis report. By and large, the single failure criterion is preserved by specifying LCOs that require all redundant components of safety related systems to be operable. When the required redundancy is not maintained, either due to equipment failure or maintenance outage, action is required, within a specified time, to change the operating mode of the plant to place it in a safe condition. The specified time to take action, called the completion time, is a temporary relaxation of the single failure criterion, which, consistent with overall system reliability considerations, provides a limited time to fix equipment or otherwise make it operable. If equipment can be returned to operable status within the specified time, plant shutdown is not required.

CONDITION A Replace: "One steam supply to turbine driven AFW pump system inoperable" with; "Turbine driven AFW pump system inoperable due to one inoperable steam supply."

Add new Condition A using an "OR" logical connector:

.............................................NOTE...................................................

Only applicable if MODE 2 has not been entered following refueling.

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

- 42 If one of the two steam supplies to the TDAFW pump system is inoperable, or if a turbine driven pump is inoperable while in MODE 3 immediately following refueling, action must be taken to restore the inoperable equipment to an OPERABLE status. The first Condition A change is an editorial change to adopt clarifying language consistent with TSTF-412. This change is an administrative (non-technical) change intended to incorporate human factors principles into the form and structure of TSs so that plant operations personnel can use them more easily.

The second change to add a new Condition A using an "OR" logical connector is consistent with STS and is being added to allow for a longer Completion Time due to the reduced decay heat following refueling. Adding a Condition for the inoperability of the TDAFW pump while in MODE 3 immediately following refueling, is reasonable because the minimal decay heat levels in this condition, the availability of the redundant MDAFW pump system and the low probability of an event requiring the use of the TDAFW pump.

The NRC staff finds that the proposed change allowing the turbine driven pump to be inoperable while in MODE 3 immediately following refueling operations is acceptable because system redundancy is required to be restored within a specified time, thus making the change a temporary relaxation of the single failure criterion for equipment outage, preventative maintenance or corrective maintenance. If equipment cannot be returned to OPERABLE status within the specified time, plant shutdown is required. Therefore, the NRC staff concludes that the proposed changes comply with 10 CFR 50.36 and are acceptable.

For Required Action A.1 replace: "Restore steam supply to OPERABLE status" with:

"Restore affected equipment to OPERABLE status."

The Required Action replaces restore steam supply with restore affected equipment to be consistent with the change in Condition A, which now addresses two conditions; an inoperable steam supply to the TDAFW pump and an inoperable TDAFW pump system. This change is an administrative (non-technical) change intended to incorporate human factors principles into the form and structure of TS so that plant operations personnel can use them more easily.

Therefore, the NRC staff concludes that the proposed changes comply with 10 CFR 50.36 and are acceptable.

CONDITION B Replace Condition B, "One turbine driven AFW pump system inoperable in MODE 1, 2, or 3 for reasons other than Condition AI! with:

"One AFW pump system inoperable in MODE 1, 2, or 3 for reasons other than Condition A."

Replace Required Action B.1, "Restore turbine driven AFW pump system to OPERABLE status" with:

"Restore AFW pump system to OPERABLE status."

The Condition and associated Required Action are revised to apply to either the MDAFW pump system or the TDAWF pump system being inoperable in MODE 1, 2, or 3. With one of the required AFW pump systems (pump or flow path) inoperable in MODE 1, 2, or 3 {for reasons

- 43 other than Condition A), action must be taken to restore the inoperable equipment to operable status. This Condition includes the loss of two steam supply lines to the TDAFW pump. This change is an administrative technical change intended to incorporate the use and application principles into the form and structure of TS so that plant operations personnel can use them more easily. Therefore, the NRC staff concludes that the proposed changes comply with 10 CFR 50.36 and are acceptable.

CONDITION C Replace "One motor driven AFW pump system inoperable in MODE 1, 2, or 3" with:

"Turbine driven AFW pump system inoperable due to one inoperable steam supply.

Motor driven AFW pump system inoperable."

Replace Required Action C.1, "Restore motor driven AFW pump system to OPERABLE status" with:

"Restore the steam supply to the turbine driven pump system to OPERABLE status.

Restore the motor driven AFW pump system to OPERABLE status."

Replace Required Action C.1 and C.2 Completion Times, "7 days AND 10 days from Discovery of Failure to meet the LCO" with:

"24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months if motor driven AFW pump system is available from the opposite unit."

The new Condition C and associated Required Action addresses the ability of the AFW system to mitigate the most limiting design basis events, excluding a single failure with an inoperable steam supply to the TDAFW pump system in conjunction with an inoperable MDAFW pump system. The Required Action requires re-establishing AFW system to meet the LCO requirements for either the TDAFW pump system or the MDAFW pump system.

The associated Required Action Completion Time requirements considers the PBNP unique design to cross-tie IVIDAFW pump systems for each unit to feed the SGs on the opposite unit.

As such, a 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time applies if the MDAFW pump system on the opposite unit is available; otherwise the Completion Time for both Required Actions is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

With the required MDAFW pump system (pump or flow path) inoperable and the TDAFW pump system inoperable due to one inoperable steam supply, action must be taken to restore the affected equipment to operable status. Assuming no single active failures when in this condition, a MSLB accident could result in the loss of the remaining steam supply to the TDAFW

- 44 pump due to the faulted SG. In this condition, the AFW system may no longer be able to meet the required flow to the SGs assumed in the safety analysis.

The 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time is reasonable based a MDAFW pump system being available from the other unit, the capability of this system to provide 100 percent of the AFW flow requirements, and the low probability of an event occurring that would challenge the AFW system. Alternatively, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time applies and is reasonable when a donated MDAFW system is not available from the other unit based on the remaining operable steam supply to the TDAFW pump, the availability of the remaining operable MDAFW pump system, and the low probability of an event occurring that would require the inoperable steam supply to be available for the TDAFW pump.

These changes take advantage of the evolution in policy and guidance as to the required content and preferred format of TS. Therefore, the NRC staff concludes that the proposed changes comply with 10 CFR 50.36 and are acceptable.

CONDITION D Replace Condition D, "Required Action and associated Completion Time of Condition A, B, or C not met Two AFW pump systems inoperable in MODE 1,2, or 3" with:

"Required Action and associated Completion Time of Condition A, B, or C not met."

Replace Required Action D.1 Note, "Each unit may be sequentially placed in MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when both units are in Condition C concurrently" with:

"Be in MODE 3."

Replace Required Action D.2 Note, "Entry into MODE 4 is not required unless one motor driven AFW pump system is OPERABLE" with:

"Be in MODE 4."

Condition D is revised to delete the Condition of two AFW pump systems, since the modified AFW system consists of only two pump systems (MDAFW and TDAFW pump systems) per unit.

Loss of both AFW pump systems is covered by Condition E. The Conditions and associated Required Actions are no longer applicable to the unitized AFW system. These changes are administrative technical changes intended to incorporate the use and application principles into the form and structure of TS so that plant operations personnel can use them more easily.

Therefore, the NRC staff concludes that the proposed changes comply with 10 CFR 50.36 and are acceptable.

- 45 CONDITION E Replace "Three AFW pump systems inoperable in MODE 1, 2, or 3" with:

"Two AFW pump systems inoperable in MODE 1,2, or 3."

The modified AFW system consists of only two AFW pump systems per unit. This change is an administrative change that incorporates the use and application principles into the form and structure of TS. Therefore, the NRC staff concludes that the proposed changes comply with 10 CFR 50.36 and are acceptable.

CONDITION F Replace Condition F, "One or more required AFW pump systems inoperable in MODE 4" with:

"Motor driven AFW pump system inoperable in MODE 4" Replace Required Action F.1, "Initiate action to restore AFW pump system(s) to OPERABLE status" with:

"Initiate action to restore motor driven AFW pump system to OPERABLE status."

Condition F and the associated Required Action are revised to be consistent with modified PBNP AFW pump system design of one MDAFW pump system per unit. This change is an administrative change that incorporates the use and application principles into the form and structure of TS. Therefore, the NRC staff concludes that the proposed changes comply with 10 CFR 50.36 and are acceptable.

TS 3.7.6, Condensate Storage Tank (CST)

As discussed in Section 3.3.1 of this SE, licensee is proposing to increase the minimum required level to be maintained in the CST in support for the upcoming EPU. In preparation for the EPU, the licensee is requesting approval of a change in the required level in TS 3.7.6 to be maintained in the CST under this AFW modification. The new minimum required CST level will be based upon the availability of both units' CSTs. With both CSTs cross-tied or individually aligned, both CST levels must be maintained greater than or equal to 21,150 gallons. With one CST cross-tied to supply both units, the CST level must be greater than or equal to 35,837 gallons, With both CSTs cross-tied to supply only one unit, the CST level must be greater than or equal to 14,100 gallons. These volumes are based upon maintaining each unit in hot shut down for one hour following a loss of all AC to afford sufficient time to align the alternate AC power source, as required by 10 CFR 50.63, NUMARC 87-00, and Regulatory Guide 1,155. The NRC staff finds the proposed increase in the minimum required levels in the CSTs to be acceptable under current licensed power conditions.

TS Surveillance Requirement 3.8.1.7 The NRC staff evaluated this change in Section 3.3.4. The NRC staff determined that the proposed surveillance requirement to be acceptable.

- 46 Conclusion Based on above evaluation of the setpoint calculations and including that the addition of Footnotes 1 and 2 are in conformance with TSTF-493 and the evolution of the new AFW system, the NRC staff finds the proposed TS changes will ensure that there is reasonable assurance that systems and components affected by the proposed TS changes will perform their safety functions.

4.0 STATE CONSULTATION

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

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding published in the Federal Register on September 21,2010 (75 FR 57525). Accordingly, the amendment meets 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 amendment.

6.0 CONCLUSION

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

Principal Contributors:

L. Brown M. McConnell D. Duvigneaud S. Mazumdar S. Gardocki B. Parks B. Heida C. Schulten N. Karipineni A. Tsirigotis G. Matharu Date: March 25, 2011

ML110230016

'SE via memo

- SE via e-mail

- - NLO wlcomments OFFICE LPL3-1/PM LPL3-1/LA AFPB/BC EMCB/BC EEEB/BC IHPB/BC ITSB/BC NAME TBeitz BTuily AKlein' MKhanna' RMathew' UShoop' RElliott

DATE 02/28/11 03/01/11 10/05/10 11/01/10 11/29/10 11/17/10 10/14/10 OFFICE SBPB/BC SRXB/BC SCVB/BC EICB/BC OGC LPL3-1/BC LPL3-1/PM NAME GCasto' TUlses **

RDennig..

WKemper

MWright * **

RPascarelli 103/25/11 03/25/11 DATE 09/17/10 12/20/00 12/21/10 01/06/11 103/11/11

v t e Letter Sequence Approval
TAC:ME1081, Clarify Application of Setpoint Methodology for LSSS Functions (Approved, Closed) TAC:ME1082, Clarify Application of Setpoint Methodology for LSSS Functions (Approved, Closed)
Initiation Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request Acceptance, Acceptance, Acceptance Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement Administration Meeting, Meeting, Meeting, Meeting, Meeting, Meeting, Meeting, Meeting, Meeting Questions 19 July 2010 2 August 2010 2 August 2010 11 August 2010 11 August 2010 31 August 2010 31 August 2010 10 September 2010 10 September 2010 8 November 2010 8 November 2010 20 January 2011 26 August 2009 22 October 2009 22 October 2009 6 November 2009 5 November 2009 16 November 2009 24 November 2009 22 December 2009 13 January 2010 1 February 2010 25 March 2010 31 March 2010 25 March 2010 25 March 2010 9 April 2010 7 April 2010 31 March 2010 1 April 2010 22 April 2010 23 April 2010 19 July 2010 26 August 2010 8 September 2010 8 September 2010 16 September 2010 16 September 2010 4 October 2010 4 October 2010 19 October 2010 19 October 2010 3 November 2010 18 November 2010 23 November 2010 18 November 2010 Answers 13 May 2010 1 June 2009 25 September 2009 21 November 2009 21 November 2009 16 December 2009 20 November 2009 30 November 2009 20 November 2009 21 December 2009 13 January 2010 26 April 2010 29 April 2010 30 April 2010 11 June 2010 9 August 2010 23 August 2010 26 August 2010 27 September 2010 28 September 2010 12 November 2010 12 November 2010 13 December 2010 13 January 2011 Results Approval, Approval, Approval, Approval, Approval, Approval Other: ML092800543, ML102371288, ML102440059, ML102810591, ML102880003, ML102880628, ML110880039, ML110880682, ML110890415, ML111080583
MONTHYEAR2009-04-08 [Table View]

ML110230016

Text

SUBJECT:

Dear Mr. Meyer:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

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